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Lagniappe
Brazil’s
Oil Find, its Energy Needs and Exports
Petrobras Ship
Paulo Arthur
By
Oliver
L Campbell
The discovery of a new oil province in the sub-salt layers
offshore Brazil has caused much jubilation in that country.
But now the euphoria is dying down, it is time to analyse just
how that discovery will impact on Brazil and the world supply
of oil. The press has had a field day and hyped up its effect,
but the fact is nothing will happen for at least five years
when the first oil is expected to come on stream.
The crude
from the Tupi discovery is likely to be one of the world’s most costly to produce, though this largely depends
on the average production per well. The fields are located
below some 7,000 feet of water and a further 17,000 feet into
the earth’s crust. This makes an astounding depth through
water and earth of 4.5 miles. Drilling is complicated by the
depth of the salt layer which in places is over a mile thick.
The salt behaves plastically and when it distorts it can cause
the drilling bit to become trapped.
Costs are
further increased because the fields are about 200 miles
out to sea. At the depth of 7,000 feet, the water is
in the Bathypelagic Zone (3,300 feet to 13,100 feet) where
the temperature remains at a constant 4º C. This inhibits
pumping the oil to land since the coldness of the water would
cause an immediate heat loss. Even though the temperature of
the oil in the reservoir may be 100º C or more, heat would
quickly be dissipated as the oil travelled along the pipeline,
and the crude could become too viscous to pump. Some operators
have overcome the solidification problem in flowlines, which
take the oil from the well to the storage tank, by insulating
them so the oil retains its heat, and also by a pipe-in-pipe
technique which does a similar job. However, with flowlines
the distances involved are relatively short.
Because
of the risk that the crude could thicken and be near to solidifying,
it is highly probable pumping to dry land will
be discarded in favour of a Floating Production Storage and
Offloading (FPSO) vessel such as has recently been contracted
for production from the deepwater Jubarte field. Use of such
a vessel comes at a high price as the following statement makes
clear, “When completed, the FPSO will be destined for
the deepwater Jubarte field in the Espírito Santo Basin
offshore Brazil. The total portfolio value of the contract
is in the range of US$1.25 billion, including the 3 years of
initial FPSO operations.”
It seems Petrobras believes the FPSO system is both cost effective
and less hazardous than laying an insulated pipeline to shore
and heating the oil at some intermediate point. We will have
to wait and see what Petrobras decides on this quite tricky
problem of collecting oil from the wells in such cold waters.
With the associated gas there are two possibilities. Once
the gas is free of water, it can easily be pumped to land for
use as such in Brazil. But if Petrobras wishes to export liquefied
gas, it can either construct a conventional LNG plant onshore,
or have a floating plant built and anchor it in the production
area.
A comparison with the Orinoco Belt and the North Sea may be
interesting. The total production and upgrading cost for the
extra-heavy crudes from the Orinoco Belt, including depletion/depreciation,
is in the order of $12 to $15, depending on the extent (API)
to which the crude is upgraded. The average production cost
for crudes from the North Sea, in quite shallow water, is about
$20 a barrel. It is most unlikely the production cost from
the Tupi fields will be less than the North Sea because of
the depth at which the reservoirs are located and the distance
from land. My guess, dependent on how prolific the wells are,
is that it will be from $25 to $30 a barrel but, with a current
price of around $90, that still leaves Brazil with at least
$60 a barrel.
The Orinoco
Belt oil fields are easily accessible and both the cluster
system and horizontal drilling are well-proven
techniques. The only problem is the oil is so viscous at 8.5º API
that it needs to be upgraded in special plants which can cost
in excess of $2 billions. However, PDVSA has a much less difficult
job technically than producing from offshore locations.
In the
North Sea, the oil fields are in water about 500 feet deep
which places them in the Epipelagic Zone (surface to 660
feet), also called the Sunshine Zone. The temperature varies
with the seasons, but it presents no problem with the oil flow
from the fields in the north part of the North Sea to the Sullom
Voe terminal in Shetland. The temperature in the reservoirs
exceeds 100º C and, since the oil has a low wax content,
it does not solidify if pumping temporarily stops.
The upgraded
crudes from the Orinoco Belt range from 16º API
to 32º API from the complex previously managed by Sincor.
The value of the 38º API Brent crude produced in the North
Sea, which is a marker crude, is considerably higher. It is
unlikely the Tupi crude, which is said to be a light one, will
match that gravity and price. But with $100 oil in the offing,
all are, or will be, highly profitable.
In terms
of the Hubbert Curve, the Orinoco Belt is just starting on
the upward slope, the North Sea crude has already peaked
and is on the downward slope, and the Tupi crude in not yet
on the graph. In terms of profitability, PDVSA wins easily
since all the difference between income and cost accrues to
the Nation. Petrobras will be in a similar situation once Tupi
production starts, except its cost will be some $10 to $15
a barrel higher than PDVSA’S.
The amount of proven reserves found in Tupi is between five
and eight billion barrels--this is not the oil in place but
the estimated amount of oil than can be recovered. Assuming
that, to become a significant player in the international market,
Brazil needs to export 1.5 million barrels a day, then Petrobras
can export at that level for nine years. If it is assumed eight
billion barrels are producible, the figure increases to 15
years. My point is these are not long periods in the context
of world demand.
Furthermore,
Brazil has the world’s sixth largest population
with 190 million people. Its GDP is growing annually at around
5 percent, and there is a strong correlation between GDP growth
and increased oil consumption which will only be partly mitigated
by the use of ethanol. My conclusion is that some of the oil
produced from Tupi will be required to meet increased internal
demand thus putting pressure on amounts available for export.
When the
Tupi discovery was made public, Brazil’s president,
Lula da Silva, said it was probable the 41 blocks close to
the Tupi find would be withdrawn from the next bidding round.
More recently, the chief executive of Petrobras has stated
he believes they are capable of producing the oil themselves.
Petrobras found the oil and it belongs to Brazil, so why should
it be shared with others? This attitude is understandable,
but does it make commercial sense? I don’t think it does
and I believe Petrobras should invite partners to develop the
41 blocks for the following reasons:
1) Financing capacity. Petrobras, on its own, may have difficulty
raising the huge sums required for the investment. If other
major oil and gas companies become partners, it would reduce
the problem since they would contribute their share.
2) Size of the operation. Petrobras could be overstretched
by trying to develop several blocks on its own and at the same
time. With joint ventures, the partners could be named operators
in some of the blocks.
3) Speed of the development. With partners, there is little
doubt development would advance quicker, the oil would come
on stream earlier, and some of the profit could be used to
finance further expansion.
4) Two heads better than one. Though Petrobras believes it
has the technological expertise, problems could arise during
development where partners may provide better solutions. Let
me mention just two techniques where other companies have a
leading edge.
The first
is Shell’s “snake well” technology
where drilling, instead of being done in straight lines, follows
an irregular, snaking pattern to access a number of small reservoirs
which can then be connected to just one production well. This
has been made possible by the development of software which
images the reservoirs, and by drills that can be steered accurately
from one reservoir to another. Drilling cost is significantly
reduced and oil recovery is increased.
The second
is ExxonMobil’s extended reach drilling (ERD)
technology. They drilled a well 37,016 feet deep--over seven
miles--on Sakhalin Island in Eastern Russia in 61 days, beating
their target by 15 days. The company claims to drill ERD wells
faster than anybody else, and says drilling times since 2003
have been reduced by more than 50 percent. This fantastic achievement
substantially reduces drilling costs.
All the above indicate a joint venture approach will be more
successful than going it alone. I believe PDVSA got it right
by forming joint ventures to develop the Orinoco Belt. The
company holds a minimum of 60 percent of the shares in each
joint venture which gives it an effective, though perhaps not
legal, control. Its only mistake, in my opinion, was to insist
on being the operator of each venture. By doing so, it has
become overstretched and lost the managerial and technical
expertise that the partners could have provided. Petrobras
could similarly hold a majority share in each block, but cede
the operation to one of its partners if this was considered
advisable.
The Venezuela government sets royalty and income tax rates
so the foreign companies do not make excessive profits and
the Brazilian government could do the same. The following example
provides some illustrative figures at two price levels.
Income and costs in US$ per barrel
| |
Tax
at 50% |
Tax
at 33% |
| Price
per barrel of a light crude |
$90.00 |
$72.00 |
| Less
crude production cost |
-30.00 |
-30.00 |
| Sub-total |
$60.00 |
$42.00 |
| Less
royalty at 33.3% |
-30.00 |
-24.00 |
| Income
before income tax |
30.00 |
18.00 |
| Income
tax (40% and 33%) |
-12.00 |
-6.00 |
| Net
income for partner |
$18.00 |
$12.00 |
| Brazilian
government take |
$60.00 |
$42.00 |
We should
congratulate Petrobras on its new discovery and hope proven
oil reserves will be increased as further exploration
takes place in the 41 blocks close to Tupi. This article tries
to go beyond the euphoria by injecting a modicum of realism
into the situation. Though 8 billion barrels is a substantial
quantity, its effect on world supply is at least five years
away and, even then, it is no more than Saudi Arabia could
produce today if it opened all the stops. Brazil’s internal
demand is increasing, and it will be some years before gasoline
shipments can be made to the rest of South America, the USA
and elsewhere. It will also be some years before the associated
gas is available to solve Brazil’s current deficit. In
brief, the Tupi find is a bonanza but not an immediate solution
to Brazil’s energy needs.
Oliver
L Campbell, MBA, DipM, FCCA, ACMA, MCIM was born in
El Callao in 1931 where his father worked in the gold mining
industry. He spent the WWII years in
England, returning to Venezuela in 1953 to work with Shell
de Venezuela (CSV), later as Finance Coordinator at Petroleos
de Venezuela (PDVSA). In 1982 he returned to the UK with his
family and retired early in 2002. Petroleumworld does not necessarily
share these views.
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Petroleumworld
News 01/19/08
Copyright© 2008
Oliver L Campbell. All rights reserved.
