I have to say that I was closer to shocked rather than surprised at the sell down of ERH this last week with the release of their market update report.
I must admit I could hear the disappointment in almost every word in the report but that disappointment has to be related to time frames and not to the actual content of the announcement because what we can be very confident about now is that there is a heap of oil, much more than the most bullish of us ever imagined. This oil is also very shallow making it very cheap to extract and is present in well known petroleum structures that have been producing for decades, so that should lead us to the conclusion that the oil will flow.
The 2 things I will cover in this report is reserve estimates and also the maths behind it and have other oil companies had the same issues we have had in the Sergipe-Alagoas Basin??
Firstly
What are we sitting on?? How much oil is there???
For that need to do the sums and that sum looks something like this
Or
Where
= STOIIP (barrels)
= Bulk (rock) volume (acre-feet or cubic metres)
= Fluid-filled porosity of the rock (fraction)
= Water saturation - water-filled portion of this porosity (fraction)
= Formation volume factor (dimensionless factor for the change in volume between reservoir and standard conditions at surface)
Gas saturation Sg is traditionally omitted from this equation.
The constant value 7758 converts acre-feet to stock tank barrels. An acre of reservoir 1 foot thick would contain 7758 barrels of oil in the limiting case of 100% porosity, zero water saturation and no oil shrinkage. If the metric system is being used, a conversion factor of 6.289808 can be used to convert cubic meters to stock tank barrels. A 1 cubic meter container would hold 6.289808 barrels of oil.
So the above is the basic sum and a break down on how to use the sum.
For us now we need to start breaking down these numbers to build our own model for estimating block 330 and to do this we have 2 points of reference,’ Paca1 and Paca2.
The biggest problem we have is that the first point of reference “Paca1” we don’t have the usable info that we have on Paca2. All we know is that there was oil shows over a 104m at Paca1 and the only area tested out of these oil shows was the 20 metre target interval in the Muribeca and Coqueiro Seco Formation. A 15 metre section out of this 20m interval was seen fit as a future producer in the Coqueiro Seco Formation.
It has became clear that the operator would have been a lot better off drilling Paca1 from scratch rather than reentering the old Petrobras well. But that’s the oil game sometimes you get lucky and sometimes you don’t and considering the operator concreted over 9m of the 15m production zone, well there was no luck here.
Anyway back to the sums
Because a lot of Paca1 was inconclusive or at the very least the required info was not released to the market for us to pull apart. We need to use what know and that is Paca1 had 104m of oil show.
Paca2 is a different beast, all the info you could ever need has been provided firstly with the mud-logs as seen below and then with last week’s announcement that gave us oil saturation, porosity and we will use the water cut from Paca1 which is currently at 14%.
In total we know out of Paca2 we got 232m meters of oil shows with 6 pay zones including;
• Coqueiro Seco Formation, Morro do Chaves Member
Limestones, sandy limestones and sandstones of reservoir quality over the interval 306m to
336m and 237 to 245.5m
• Penedo Formation
Sandstones of reservoir quality over the interval 339m to 345m
• Barra de Itiuba Formation
Sandstones of reservoir quality over the interval 400m to 418m
Totaling 54metres of pay zone
The average porosity of this pay zone is
· EEE zone 13%
· DDD zone average porosity greater than 23%
· Upper CCC zone 27%
· Lower CCC zone 20%
· Penedo formation 22%
· Barra de Itiuba formation 27%
Using these averages in this 54m-pay zone we get average of 23.4% porosity taking into account the measurements of each pay zone and the porosity in each zone.
I like to go on the down side of things so I will use and average of 12% porosity for the rest of the oil shows.
The average oil saturation for Paca2 is as follows
· EEE zone 68%
· DDD zone average porosity greater than 67%
· Upper CCC zone 53%
· Lower CCC zone 70%
· Penedo formation 51%
· Barra de Itiuba formation 50%
Using these averages in this 54m pay zone we get average of 59.83333% oil saturation taking into account the measurements of each pay zone and the oil saturation in each zone.
At this point we have to start making assumptions on how the structures will play out over the full 27 square Km blocked that has been roped off as the Paca oil field.
In the below picture shows some seismic taken of 330 with the location of Paca1, Paca2 and a guess on where they will locate Paca3.
We know that we lose about half of the oil producing structure when we move from the up-dip appraisal well (Paca2) to the down dip well Paca1, Based on the oil shows at Paca2 being 232m and Paca1 104m and pay zone of 54m at Paca2 compared to a pay zone of 20m at Paca1.
We see that in the seismic data that the contour lines in the block have a much slower rate of decline and we start to see the formations flatten out for a large portion of the block. So based on this I am going to use the assumption that the oil field has an average of an 80m oil column with a porosity 20% and with an oil saturation of 50% also using the 14% water cut of Paca1and a gas content of 30%
With the above assumption we get a sum that looks something like this.
· Firstly we need to work out the land mass in this case it is 27sq kms times 80m or
We know we have 27sq kms and to get this lets say the oil field is 9kms long and 3kms wide or 9000m X 3000m=27,000,000.00squared meters or 27sqkms.
· Now times the 27,000,000 by the depth or
27,000,000 X 80= 2,160,000,000.00sq meters
· 1 squared metre can hold 6.24 barrels so now we times the total squared metres by 6.24 or 2,160,000,000.00sq X 6.24= 13,478,400,000.00
· We are working off a 50% oil saturation factor so we now times the squared meters converted into barrels by .5 or
13,478,400,000.00 X .5= 6,739,200,000.00
· We are also working off the assumption that we have an average porosity of 20% so we now times the 6,739,200,000 by .2 or
6,739,200,000.00 X .2= 1,347,840,000.00
· We are also using the assumption that we will have a 14% water cut so we now times 1,347,80,000 by .86 or
1, 347,80,000 X .86= 1,159,142,400.00
Using all the above assumptions in the above figures we can assume that our oil in place figure now stands at 1,159,142,400.00. We now need to work out the recovery factor which is according to the company 17% so we now times the oil in place by .17 or
1,159,142,400.00 X .17= 197,054,208.00 recoverable barrels.
To bring this number back to STOOIP we need the gas content or the oil shrinkage which in this case is 30% so we now times 197,054,208 by .7
This leaves us with a total of 137,937,945.60 Stock tank barrels and with ERH share of 40% = 55,175,178.24 STOOIP.
Ok so that’s that as far as working out our recoverable stock tank barrels and also how to start setting up your model for working this out. You can if you wish start building into your model things like NPV valuations like this; we know that in 27years we have to renew the production lease on 330 so you can add the assumption in that we want to drain 330 within this time frame so you would use a sum like this 137,937,945 / 27 = 5,108,812.80 barrels per year. ERH gets a 40% share of that which equals 2,043,525.12 or an annual income of around $49m P/A using an average profit of $24 per barrel.
Below is a NPV spreadsheet based on the above assumption.
Once you have a grasp of the basics you can change them to suit yourself or run as many probables as you like. You may have noticed that I started off by breaking up the oil shows with the production area then bought them back to one average, you may prefer to run with 2 sums one for the oil shows and one for the production zone and then bring the end number together.
But remember always err on the side of caution, if you work off the fundamentals then run your discount rates higher than what you think they should be and so on.
Ok ok time to move on and one thing I keep hearing around the traps about 330 is concern about the API gravity of the oil, which is currently 12 to 14 out of Paca2. The concerns are that the oil is to heavy and wont flow.
330 was never going to free flow it is way too shallow for that and was always going to be under pump. The oil is heavy, any oil that has an API gravity higher than 10 and less than 22 is considered heavy but there are heaps of oil fields the world over that have excellent flow rates, the below all have API gravity ranging between 12 and 17.
Gannet East was discovered in 1982 and was deemed uneconomical at the time. In response to the higher oil prices of the mid 1990’s, development planning began in 1996 and first production was in January 1998. The key ‘breakthrough’ was the use of ESPs. The field’s main features are:
Heavy Oil in the Forties Formation, a consolidated reservoir: 144 million barrels in place.
Strong aquifer, so natural drives only – no injection or pressure support of any kind.
One initial well, horizontal and producing 17,000 bopd; water breakthrough by July 1998.
Two additional horizontal wells drilled in 2000 and 2001.
Surveillance, using both 4D seismic and PLTs, and fluid sampling, using PVTs, has been a major focus.
Depending on future developments, recovery factors are envisaged to be 29-35%.
Captain is a rather different beast that went on production in early March 1997. The field’s main features are:
Heavy Oil and some gas in 4 formations, with probably just less than 1 billion barrels in place.
Significant sand production.
Insignificant natural drive: major water injection, envisaged at up to 400,000 bwpd.
Many complex wells, with extensive use of both ESPs and HSPs.
Surveillance a key, with PLTs to the fore.
Production circa 70,000 bopd: just less than 150 million barrels produced by the end of 2004.
Grane is an especially useful North Sea example to look at, as Hydro have been very open about their approach to the field and going onto production as late as 2003, it has benefited from much new technology. The field’s main features are:
Heavy Oil in the Heimdal Formation, a consolidated reservoir: probably just over 1.5 billion barrels in place.
No natural drive: gas imported for immiscible gas injection to provide the pressure to move the Heavy Oil.
Horizontal wells envisaged from the outset; nowadays, horizontal wells with multilaterals.
Surveillance is a key; a major focus on seismic, both 4D and permanent monitoring from the seabed.
Peak production (March 2006) of 243,000 bopd: a recovery factor of 55% is foreseen compared to a maximum of 35-40% that could be anticipated from a waterflood
Yes heavy oil can be a tricky beast to flush out but the one thing we have in our favour is the fact we have natural drivers i.e. the gas content of the oil and we already know we have permeability because Paca1 flows.
With all the info at hand this to me is now just a waiting game unless any new news comes to the market I can find no reason to panic and about 197,054,208 reasons to buy.
But as always do your own research.
As promised I will cover other oil fields in the Sergipe-Alagoas Basin and any info on issues that were encounter when testing began in a few days.
Cheers
