Tiber Oilfield Spells Major Upside for Prices 24 comments
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On September 2, London-based Super Oil BP Plc [London: BP], (NYSE: BP) announced the discovery of a large oilfield, dubbed Tiber, located in the deepwater Gulf of Mexico. The field is 62 percent owned and operated by BP, while Brazil’s Petrobras (NYSE: PBR) and ConocoPhillips (NYSE: COP) own 20 and 18 percent of the find, respectively. The technical challenges BP encountered in drilling this prospect have been immense. The field is located in waters more than 4,000 feet (1,220 meters) deep, and the total length of the well itself is more than 35,000 feet (10,685 meters)--more than 6.5 miles long from the bottom of the drilling rig to the bottom of the well. The pressures and temperatures encountered at such depths tested the physical limits of drilling materials and technology. In fact, just a few years ago most producers and industry pundits felt drilling such a long well in deepwater was technically impossible. For BP, Tiber is an important find and further demonstrated the company’s competence. In the deepwater Gulf of Mexico, BP is the largest leaseholder, has the largest remaining reserves and is the largest producer, pumping 400,000 barrels of oil equivalent per day. The company suggested that Tiber will be bigger than another recent discovery made in the region, the so-called Kaskida find. Since Kaskida is estimated at around 3 billion barrels, this implies that Tiber could be one of the largest oilfields discovered anywhere in the world in the past two decades. Tiber could rival in size some of the major deepwater discoveries offshore Brazil over the past three years such as Tupi. Not surprisingly, soon after BP announced its discovery headlines screamed about a giant new oilfield with reserves equal in size to an entire year’s worth of Saudi Arabian oil production. Some pundits predicted that this surge of new supply would put downward pressure on oil prices, the huge reserves in the Gulf of Mexico seeming proof that global oil production can rise fast enough to meet long-term growth in demand. As impressive as the Tiber discovery is, the latter argument just doesn’t hold water; take great care when absorbing sensationalist headlines about new discoveries. The basic problem is that many confuse oil reserves with oil production and reserves can be a misleading concept. The reserve estimates you often hear quoted in the news are for estimates of original oil in place (OOIP), the total amount of oil contained in the reservoir. But oil and gas aren’t found in giant underground caves or lakes. These substances are actually trapped in the pores of rocks. Some of this Tiber oil is stranded in sections of the field where the rock is impermeable--the oil can’t flow into the well. And some will simply be left behind during production; there’s no way to “pump” it out as if it were in storage. Typically, a producer won’t recover anything close to 50 percent of the OOIP even after many decades of production. In the case of Tiber, it’s likely that even if OOIP is more than 3 billion barrels producers will only extract 500 million to 1 billion barrels of oil, a recovery rate of as high as a third. And this production will come over decades. Don’t make the mistake of assuming that 500 million barrels of recoverable oil means producers can extract 1.35 million barrels a day over a one-year period. The reality is that the Tiber field won’t go into commercial production until the latter part of the coming decade. And current estimates are that BP’s new deepwater discoveries will allow the firm to boost output from the current 400,000 barrels a day to more than 600,000 by 2020. Thus, the real impact is an incremental 200,000 barrels a day of production, a nice boost for BP but barely a drop in the bucket when you consider global oil consumption of more than 80 million barrels of oil per day. But 200,000 barrels a day of incremental production 11 years from now just doesn’t sound as exciting as more than 3 billion barrels of oil in 65 million year-old rocks under the seafloor; that reality doesn’t get much media attention. This brings me to another common misconception about the oft-used term “peak oil.” Many investors I speak to appear to be of the impression “peak oil” means that the world is literally running out of oil. That’s not the case. “Peak” refers not to the amount of oil in the ground but to the rate at which it can be produced. In other words, the world consumes more than 80 million barrels of oil per day, and demand is likely to grow long-term due mainly to increased consumption from developing countries. The real question isn’t how big global oil reserves are or how much can ultimately be recovered. The question is how quickly they can be produced. If the world demand grows to 90 million barrels per day over the next five years, one of two things must change: Either prices will need to rise enough to choke back demand, or producers will need to ramp up capacity to 90 million barrels a day. But new production from fields like Tiber in the Gulf and Tupi offshore Brazil is counterbalanced by declining production from existing, older fields. Consider the following chart of oil production from the UK and Norway, the two main producers in the North Sea. Source: BP Statistical Review Production of oil from these two countries approximates North Sea production. The UK’s two major fields, Brent and Forties, went into production in 1975 and 1977, respectively. Norway’s major fields started going into production in the early 1970s and underwent major rehabilitation programs to boost production in the ’80s. At any rate, the chart shows that not long after these giant fields entered production, North Sea oil production began to soar. The initial growth in production was rapid; the North Sea finally entered a sort of plateau period in 1995. Production peaked early this decade and has since fallen precipitously. Although these fields will still be yielding oil (and gas) for many years to come, the production rate will continue to fall. That’s despite the fact that some estimate that many North Sea oilfields still contain 70 percent of their OOIP. Most fields follow some version of this “bell curve” production profile. In other words, production ramps up quickly when a field is first produced because underground pressures are high; natural geologic forces drive production. But at some point, as pressures fall, production hits a plateau. This occurs long before all the OOIP is recovered. At this point, the producer can use certain techniques to stabilize pressures and increase production. However, these factors are unlikely to do much more than simply stabilize production at relatively high levels. The biggest beneficiaries of these trends: the oil services industry, including companies like Schlumberger (NYSE: SLB). As production from existing oilfields decline, producers will need to drill more aggressively and use more sophisticated production techniques to stem decline rates. And as production from easy-to-produce fields wanes, producers will be forced to target ever more complex fields such as those in the deepwater. The oil services industry is the main purveyor of that sophisticated technical know-how both to big international producers like BP and to state-owned oil companies like Saudi Aramco. The other implication: To make such spending and development cost-effective, oil prices will need to remain elevated. Ironically, the discovery of giant new fields like Tiber foreshadows far higher, not lower, oil prices in years to come.
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"The reserve estimates you often hear quoted in the news are for estimates of original oil in place (OOIP), the total amount of oil contained in the reservoir."
This is incorrect. When someone uses the term "reserve" or "reserves", by definition this is what is recoverable. The word "resource" is used at times to define something less certain.
2020 sounds like a long time from now!!
The one very minor addition I would throw into the mix is that any oil company going after this kind of find (not much oil, very expensive, production likely 7 to 10 years away) is that they have no better options. A fundamental issue with peak oil is that before the global production peaks we encounter much higher production costs simply because the easy, cheap oil can no longer meet demand.
that oil is going to China
along with gas from the gorgan field from western australia
oil from south america
oil sands from canada
think the chinese are onto somthing????
they may not be sending any oil to the US within 5 years
world supplied for approx. 14 days (@ 70 billion barrels/day)
Another hugh factor will be the fact that the Alberta Canada oil sands companies are gearing up to increase pipeline capacity to pump more crude oil to the US Gulf oil company refineries.
Good information in this article just the wrong headline. Crude oil prices will continue to fluctuate and follow the price of gasoline at the pump instead of in reverse. That is not the case with distillates with prices in lockstep with the price of crude oil. Diesel and jet fuel will move 2.5 cents per gallon for every $1 a barrel of crude oil.
BP's former chairman Sir John Browne divulged during an interview for 60 Minutes in November 2006 that the crude oil in deepest part of the Gulf of Mexico could be brought in for $40 a barrel. Any price they fetch over that will be pure profit.
Actually, they're both counted as "reserves". The difference is between "proven" (likely to be recovered), and "probable" (referring to overall potential).
I don't get a chance to say that to many people.
Dave Cohen
columnist, aspo-usa
Among the many fine comments Kiwichick's are worth noting. Kiwichick, you did overlook one Chinese move to provide oil for its needs, the activity in Africa. While China is pursuing a coherent policy to insure its future supplies, it also is working on making oil much less of a vulnerability by actually building alternate energy sources. Sounds like a plan. Maybe we should take note.
The bottom line is that oil is going to become very expensive, sooner rather than later.
The point about "Peak Oil" is lpossibly unclear though. As I understand it, the term originally came from the "Hubbert Curve" analysis which demonstrated that under normal drilling conditions, conventional oil fields grow and decline in what is basically a bell curve. Accordingly, they reach a peak at some point in their life which is referred to as the point of "Peak Oil". The model is surprisingly accurate for conventional production in the US as well as Mexico, the UK and Norway (see graph above or google US and Mexican production). Likely it is also true for Saudi Arabia and Russian conventional wells also.
Theoretically, the model can be applied to worldwide global conventional production and if you restrict your discussion to conventional oil production there is very little legitimate debate about this point.
The caveat, however, is that it Peak Oil has not been demonstrated to work for unconventional drilling. It is quite likely for instance the Oil Sands production will not follow the traditional growth and decline model. It is also unclear whether horizontal drilling and very deep wells will follow this pattern as closely either.
The interesting debate is to what extent unconventional production can offset post Peak Oil declines in conventional production?
What is assumed in this article is that the vast majority of oil production comes from conventional drilling and unconventional techniques are only now gaining prominence as higher oil prices justify the increased costs associated with them. I think that is probably an astute point.
At some point in time we will likely experience peak oil production in conventional oil. The extent to which that is ameliorated by unconventional production will likely be a function of price and opportunity. To the extent this analysis is correct, the oil field companies should see some serious upside at some point in their longer term future.
1. Reserves do NOT represent the total amount of estimated oil in a given resource as "proven" by geologic assessments and initial drilling. In fact, the reserves of a given well or resource can change year to year on a company's balance sheet, regardless of new finds or depletion. This is caused by the fact the reserves are a function of the amount ECONOMICALLY recoverable oil. So, with low oil prices, it may not be economic for a company to lift the last bit of oil out of the ground. However, if oil prices rise, it would be economic to make extra investment in the well such as injection and recover the last bit of oil. In this case, the company's reserves would increase even though no new oil was found in that well. I recently learned this distinction in talking to a domestic E&P company.
2. Another point about Peak Oil, not only does the rate of production decline after reaching Peak, the cost of recovery goes up. To get the final bit of oil from a well requires injection and other techniques, which add to the cost of recovery. Another point is that most of the easy oil finds and recoveries have been made. New oil discoveries are being made in areas where recovery is difficult and expensive.
Transocean Ltd. (NYSE:RIG) today announced that its ultra-deepwater semisubmersible rig Deepwater Horizon recently drilled the deepest oil and gas well ever while working for BP and its
co-owners on the Tiber well in the U.S. Gulf of Mexico. Working with BP, the Transocean crews on the Deepwater Horizon drilled the well to 35,050 vertical depth and 35,055 feet measured depth or more than six miles.
So why recommend SLB when you should be recommending RIG???
On Sep 07 09:00 PM kiwichick wrote:
> user 482953; re oil in Kurdistan
>
> that oil is going to China
>
> along with gas from the gorgan field from western australia
>
> oil from south america
>
> oil sands from canada
>
> think the chinese are onto somthing????
For one thing, most deepwater rigs are contracted for years into the future at fixed or gradually adjusting indexed day-rates and thus see little or no near-term benefit from a particular discovery or jump in demand. For example, the rig you highlight is contracted to BP through October of 2010. RIG has a total of 18 ultra-deepwater floaters but a quick glance at their latest fleet status report shows that most are already committed. Three of those 18 are available for re-contracting next year, 5 in 2011, 2 in 2012 and the remainder after that. While this provides predictability of cash flow and earnings visibility it means that RIG only sees upside gradually from rising deepwater interest and demand.
If you're looking for a more direct play on accelerating deepwater development one area to keep an eye on would be subsea equipment producers like FMC Tech (FTI) or Cooper Cameron (CAM)
On Sep 08 08:23 PM William M. Wright wrote:
> Why are you recommending SLB on this find? Seems to me RIG is the
> best play for this and other deepwater drilling. This huge pool of
> oil is trapped 35,000 feet below the Gulf floor in a geological area
> known as the Lower Tertiary trend. That's nearly a mile deeper than
> Mount Everest is high !
>
> Transocean Ltd. (NYSE:seekingalpha.com/symbo...) today announced
> that its ultra-deepwater semisubmersible rig Deepwater Horizon recently
> drilled the deepest oil and gas well ever while working for BP and
> its
> co-owners on the Tiber well in the U.S. Gulf of Mexico. Working with
> BP, the Transocean crews on the Deepwater Horizon drilled the well
> to 35,050 vertical depth and 35,055 feet measured depth or more than
> six miles.
>
> So why recommend SLB when you should be recommending RIG???
> If you're looking for a more direct play on accelerating deepwater
> development one area to keep an eye on would be subsea equipment
> producers like FMC Tech (seekingalpha.com/symbo...) or Cooper
> Cameron (seekingalpha.com/symbo...)
Absolutely correct.