Tech Talk - The Rise and Fall and . . . . of Brazil

Brazil seems to be appearing in the news a little more regularly these days. Whether it is because the President objects to NSA activities or because Unilever is buying 3 million gallons of algae-produced oil from Solazyme, to be produced at a new plant in Brazil that will generate 30 million gallons a year, the emphasis has switched from a focus on their growing oil and ethanol economy, perhaps because it has stopped growing.

Back when The Oil Drum first started (where the last post has now gone up) one of the earliest posts noted that Petrobras was seeing a 14% increase in production, as they reached 1.82 mbd, back in May 2005. This was at the time that discoveries were being made offshore in what is now known as the Pre-salt deposits.

Figure 1. Nature of the offshore deposits that are being developed from under the Salt Layer. (Seeking Alpha )

Part of the problem with the development of these deposits comes from where they are and what they are. Rock salt is one of those materials that will flow under pressure. (One of the more interesting examples of this is in the Polish salt mine at Wielicza where old mining tools were found encased in salt in a region of the mine that was thought to have never been worked.) This poses some problems with drilling – although these are now relatively well understood. The other problem is that the reservoir rocks under the salt are recognized to be very weak, which makes it more difficult to drill long lateral holes, and keep them open. (The genesis of the basin has been described by Schlumberger).
Note: this post has been updated to include the new discovery in the SEAL-11 area.

Exploration first found the Espirito Santo, Campos and Santos basins and this was followed, in 2006, by the Tupi province which held the promise, at the time of discovery, of producing 8 billion barrels of light oil and natural gas.

Figure 2. The initial Tupi discoveries offshore Brazil (Offshore Technology )

Because of the location offshore the oil and natural gas would be recovered using a Floating Production Storage and Offloading unit (FPSO) and the first of these to be dedicated to the site was contracted in 2009, the first crude being produced in May, 2009. An earlier FPSO, the Cidade de Sao Vincente, was already in use as a test platform for the field. At the same time further development showed that three offshore fields (Tupi, Iara and Guara) held the potential to supply up to 40 Tcf of natural gas. Guara was discovered in 2008, and was initially anticipated to have 1-2 billion boe potentially available. Iara was also discovered in 2008, and holds a potential 3-4 billion barrels of light oil and natural gas. By the end of 2010 the collective potential for the three fields was estimated at 10.8 billion boe.

Figure 3. The development blocks around Tupi (Rigzone )

A second FPSO was ordered in June of 2010 with a capacity of 120 kbd of oil, and 5 mcf of natural gas. Initial production from the first FPSO, the Cidade de Angra dos Reis, began in October 2010 with a target of 100,000 bd, and an additional eight FPSO’s were ordered in November of that year, increasing capacity by up to 150 kbd each, although collectively they are anticipated to reach maximum production in 2017 at 900 kbd.

At the end of 2010 the Tupi development had been renamed as the Lula field, in honor of the retiring President, and two more FPSO’s were chartered to increase production by another 150 kbd each, from the fields of the region. By May the first well connected to the FPSO Cidade do Angra dos Reis was producing over 28 kbd as the first of six wells connected to the platform.

As the development of the platforms to commercial production became closer Petrobras also commissioned the construction of 2 more FPSO’s, noting that these would be able to inject some 200 kbd of water back into the formations, in order to assist with production and the maintenance of pressure.

By June of this year the first production was received on the Cidade de Paraty a third FPSO, although only at 13 kbd, rather than the target 25 kbd as the vessel and support structure was still in process. The platform will ultimately receive oil and gas from 7 production wells (for a total capacity of 120 kbd) while feeding water back through 6 injection wells.

The potential is thus evident for Brazil to become a significant producer to meet not only their domestic demand, but also to start exporting oil and natural gas, given the potential for these offshore fields. But, to date, this promise has yet to be fulfilled. Ron Patterson has been plotting production and I have taken this plot from his site.

Figure 4. Production of crude and condensate from Brazil (Ron Patterson )

As I noted last time, the EIA had been projecting that Brazil would be producing up to 2.8 mbd by the start of this year, rising to 3.0 mbd at the end of the year. The OPEC MOMR suggests that they will only make 2.67 mbd by the end of this year, but at the above chart shows, that would still be a considerable improvement, and reverse the drop.

The gain is anticipated to come from the FPSO Pappa Terra, which is the renamed Nisa, and which will be moored at the Pappa Terra field. This is in the Campos Basin, and is a heavy crude (API 14 – 17 degrees) with the potential to yield 380 million barrels.

Figure 5. Location of the Pappa Terra Field (Offshore Technology )

The vessel left China at the end of last year, and was completed in Brazil before sailing to the field in June.

Figure 6. The Pappa Terra FPSO (Shipbuilding Tribune )

On the other hand Brazilian production of ethanol had gone up by 6%.

UPDATE: Just after I had finished writing this Reuters carried a story which they had pieced together from other reports, and which indicates that Petrobras and an Indian partner have found a new large field of light crude about 1,000 miles north of the developments in the Lula area. The new discoveries have the advantage of not being covered with the salt layer, and so will be easier to develop. Currently production is anticipated for 2018.

Figure 7. Location of the new field off the coast of Brazil. (Energy-pedia)

There are a number of different development wells being drilled in the region, and they have found sufficient success to allow their results to be congregated into a field with a potential reservoir of 3 billion barrels of light oil. of which perhaps 1 billion will be produced.

Figure 8. The drilling blocks in the Sergipe Basin. (Petrobras) ,

Deepwater Oil Spill - of plumes, and drillships, FPSOs and the ASJ

The National Oceanographic and Atmospheric Administration (NOAA) has now tested water samples from oil plumes at three sites in the Gulf of Mexico, at varying distances from the Deepwater Horizon oil spill.

NOAA Administrator Jane Lubchenco said that the tests conducted at three sites by a University of South Florida research vessel confirmed oil as far as 3,300 feet below the surface 42 miles northeast of the well site. Oil also was found in a sub-surface sample 142 miles southeast of the spill, but further tests showed that oil is "not consistent" with oil from the spill.

Lubchenco said the water analysis "indicate there is definitely oil sub surface. It's in very low concentrations" of less than 0.5 parts per million. Additional samples from another research vessel are being tested, she said.

To place these samples in context, consider first the locations at which they were taken.

Locations of the oil sampling sites reported by NOAA The red star is the well, and the oil from the well was found at the two sites (surface and sub-sea) North of the well, while the green spot which marks the site South of the well which was contaminated with oil from another source.


The oil in the southern location may potentially come from a source which also generated the tar balls on the Florida keys recently. This was the map of natural seeps that I put up the other day.

Reported natural seep locations in the GOM.

It is germane to also note that the concentrations of oil in the plume are at a level of 0.5 ppm. In context that means that there is 0.5 cc (or roughly 0.4 gm) of oil in a cubic meter of seawater. This is not discernable to the naked eye. Thus when a news report (such as that from Sam Champion on the ABC World News) talks of the oil plume and shows the blobs of oil that he saw subsurface in a dive some weeks ago, it is effectively deceptive, since the correlation of the plume with that visual conveys the impression that the plume contains a high concentration of oil. In fact the water appears clear, and were this fresh water and the oil were instead Benzene, EPA would let you drink it. At this level, if it takes 3.43 grams of oxygen to biodegrade a gram of oil, then it will only require about 2.7 gms of oxygen to treat the cubic meter of seawater. Since oxygen is somewhat scarcer deeper in the ocean it may much slower that the 100 gm/cu m/day that I mentioned as the top rate in an earlier post But on the other hand it is not likely to take months.

This relatively short-life for the oil after it is dispersed contrasts with the remnants of the oil that was not dispersed, in the colder waters of Alaska, after the Exxon Valdez oil spill. Remnants of that oil still remain 21 years later, and can be found as emulsions, tar balls, and trapped liquid. The suggestion by Jean-Michel Cousteau that the oil should have been left untreated, so that it could rise to the surface and be collected by skimmers, does not recognize that in many conditions skimmers are only able to collect about 15% of the oil, and that in large volumes (as with the Alaskan example) oil, once it reaches the shore, can survive for decades. Better surely to break it into small droplets that are degraded and disappear. And in that regard one of the benefits of adding Corexit to the oil is that it both breaks it into these small droplets, and that in the process it reduces their chance of floating on the surface and contaminating surface dwelling fauna. Corexit even works in cleaning marshes.

In other current developments, the flow of oil from the LMRP and cap over the well, continues to increase.

For the first 12 hours on June 8th (midnight to noon), approximately 7,850 barrels of oil were collected and 15.2 million cubic feet of natural gas was flared.

That increased flow (achieved by reducing the choke on the outflow pipe) can be seen indirectly by comparing the current picture from the Skandi ROV 2 with that earlier.

The small triangular pieces at the bottom of the cap are now well clear of the plume, showing the reduced flow.

As a result this increased flow is exceeding the capacity of the existing fleet sitting over the well. Upstream Online is reporting that as a result BP is bringing a Floating, Production Storage and Offloading (FPSO) vessel and a shuttle tanker, the Loch Rannoch, from its station off Shetland to the Gulf. (The Loch Rannoch was involved in another BP accident, a collision that stalled production at the Schiehallion field at the end of last year.

“The crash happened when the 130,000 tonne tanker was docking to take oil from the 144,000 tonne BP platform for transfer to the Sullom Voe terminal, off Shetland. Its only hose-reel used for exporting the oil was damaged in the collision,” the newspaper reported.

And a BP spokesman was quoted as saying that the Schiehallion FPSO was not back in production yet. (November 3rd).

The Loch Rannoch is an 850,000 barrel shuttle tanker, that carried oil from the FPSO at Schiehallion to Sullom Voe in Shetland.


The FPSO is a different sort of vessel. This is the one at Schiehallion (And I don’t think it is coming since it still has an oilfield to service).

The Schiehallion FPSO

At a top speed of 14 knots, and having left last Wednesday, with a stop in Rotterdam, it may still be a while. That will free up the drillship to move on to other things, providing they have an FPSO by then.

And one last point in this series of shorter items that has filled the news today, I had mentioned using an ASJ to cut outwards from the inner pipe of a series of casings, but the illustration I gave earlier had the pipe cut from the outside. This one (the outer casing diameter is 26 inches) was cut from the inside.

(Courtesy ANT)

And this shows the relative sizes and where the cut was made. It is needed as one of the final steps in the abandonment of the well.

(Courtesy ANT)

Perhaps BP might use it when they finally abandon the well.
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