Tapping into deep-water reservoirs
Breakthrough technology and the innovative use of undersea equipment normally found onshore or on sea-level platforms make oil production possible at the Parque das Conchas project.
The location of the fields, 120 kilometres off the coast of Espírito Santo State, Brazil, the water depth of nearly two kilometres, and the scattered nature of the reservoirs posed daunting technical challenges. So too did the low reservoir pressure — meaning the oil would not flow freely — and the near-freezing temperatures on the seabed. Shifting sands and the powerful swell of the Atlantic Ocean added to the hurdles.
To develop the fields economically, the three Parque das Conchas fields – Ostra, Abalone, and Argonauta – were connected through a single production process centred on a specially converted floating, production, storage and offloading vessel.
Drilling through shifting sands
Gunnar Holmes who was Senior Operations Geophysicist on the project, and Lee Stockwell, former Senior Petrophysical Engineer, speak about drilling challenges
Title: Deep-water drilling
Duration: 3:38 minutes
Description:
Two engineers describe deep water drilling techniques being used by Shell Brazil
Deep-water drilling Transcript
[Background music plays]
Bright, uplifting music
[Opening titles]
[Video footage]
Shell tanker drives past at speed. Many shots of Shell employees at work, they multiply to fill the screen.
[Text displays]
Shell People
Interview with Lee Stockwell
[Title]
Senior Petrophysical Engineer, Shell Brasil.
[Lee Stockwell]
BC10 is a fairly complex project in terms of its subsurface. We have several different fields. In phase one there’s three fields that we’re working all together.
[Video footage]
Close up of Lee talking face on to camera.
[Animated sequence]
3D animation of map showing the oilfields Ostra, Abalone, Argonauta and Nautilus and their relative depths. The colours of Argonauta change from grey to glowing green, yellow and red. The shape changes to show the heavier oil.
[Lee Stockwell]
These three fields are very different from one another, and that increases our complexity here. We have Ostra, which essentially is the backbone of our phase one development; we go from heavy oil at Ostra to very light oil at Abalone. We’ve got two reservoir deposition environments that are completely different. If we move over to Argonauta complex, the B-West is in phase one, and it again is very, very different, you’re in a position with even heavier oil in an area that doesn’t have a lot of stratigraphy, lot of dip, incline to the formation.
[Video footage]
Close up of Lee talking face on to camera.
Interview with Gunnar Holmes
[Title]
Geophysicist, Shell Brasil
[Gunnar Holmes]
The geology of the Campos basin is such that you’ve got mountains right near here, Rio, for example, where they are almost 1,000 metres above elevation, and where we’re drilling is almost 2,000 metres below sea level. So the sand has basically moved about 150 miles, or 200 kilometres from these mountains here, all the way offshore, and they’ve travelled into the BC10 area for, you know, tens of millions of years.
[Video footage]
Close-up of Gunnar Holmes talking about Campos basin. Colourful diagrams are on the wall behind him.
[Animated sequence]
3D animation of well site for geological illustration. Markers show in red and green.
[Gunnar Holmes]
One of the markers we’re using in the BC10 area is called the KT [unclear] or the top cretaceous. This is a major event and marker for us in the BC10 area as it is over most of Brazil, and throughout the Atlantic Ocean. This particular event is about 60 to 65 million years old, and it’s where there was a mass extinction. We think that a number of dinosaurs and animals went extinct at that time, or at least a large number of species, and above that zone, as you get younger than, say, 60 million years old, we get into other sands that we have discovered at our oil field.
The sands that we encounter at depth are still fairly uncompacted, it means they’re just a lot like beach sand. So if you consider going out to the beach and then trying to dig a hole in the beach sand, where the waves are coming in, the water is trying to fill that hole in, basically the sand and water basically just slops or drops right into the bottom of the hole. What we’re trying to do is basically as we drill these holes we’re trying to hold that back.
[Video footage]
Close up of Lee talking face on to camera.
[Lee Stockwell]
As we go through these wells, we have the opportunity to acquire data in terms of putting tools down hole, accessing things through electrical measurements, through nuclear measurements, actually taking pieces, physical pieces of rock and fluids from the well, and actually sending these to labs and getting data analysis run on them.
One of the great technologies that we’re using here at BC10 is the ability to geo-steer. Essentially that means being able to reactively move, place the wells in the subsurface. Now, the way that we’re doing that now is using a deep resistivity azimuthal reading tool. Now what does that do for us? Essentially as we’re drilling these wells with standard tools, we can only see a couple of inches from the tool into the borehole. With this new tool, this deep reading azimuthal resistivity we can see three to five metres out into the formation.
And what that allows us to do is stay within our reservoir with greater ease. So as we see non-reservoir approaching, we can steer away from that, and that optimises the productivity of our wells. And we’ve brought in new technology, and we’ve set ourselves up to succeed. I think that from a subsurface standpoint, being able to deal with that uncertainty is obviously overcoming a challenge.
The sand that forms the layer containing oil and gas at Parque das Conchas has travelled a short distance in geological terms from Brazil’s coastal mountain ranges, 1,000 metres above sea level, to fill the Campos Basin. But the steep angle of the sand’s flow – which ends 2,000 metres below sea level 120 km from its origin – has left the sand relatively little time to settle, making drilling more difficult.
“Drilling down thousands of metres into the uncompacted seabed in the Campos Basin is like trying to dig a deep hole in beach sand,” said Gunnar Holmes, who was Shell Brasil Senior Operations Geophysicist working on the project. ”We drill down thousands of metres and sand and water pours back in.”
To prevent sand, mud and shale from filling the well during drilling, Shell pumped a mix of synthetic oil with additives into the well under high pressure to shore it up before installing a permanent steel casing. Engineers then installed perforated pipes covered by several layers of mesh that act as a sieve to stop sand from flowing into the well, but allowing oil and gas to enter.
Tools that can make electronic and microscopic measurements helped engineers drill with pinpoint precision. For the first time, Shell used technology that gives a detailed picture of geology three to five metres away from the well while it is being drilled. This technology allows engineers to steer drills in response to a continuous flow of geological information.
“That means we can steer the path of the well as we drill and stay in the best reservoir,” said Lee Stockwell, who worked on the project as a Shell Senior Petrophysical engineer.
First oil and gas separators on the seabed
Remote-controlled submarines helped to install 1,500-horsepower electric pumps on the seabed — each with the power of a Formula 1 engine — to push oil to the surface, since the natural pressure inside the reservoirs is too low. Just as a fast-flowing river resists freezing, the six pumps on the seabed help prevent the oil from freezing. They also stop wax from forming under the high pressure and low temperatures in the 78 km network of production pipes. This was the first use of electrical submersible pumps in a full-field development.
In another industry first, machines separate oil and gas on the seabed, rather than on the surface. Without first separating the oil and gas, the electric pumps — designed for liquids — would struggle to force oil to the surface. Any gas entering the pumps could cause damage and lead to pump failure.
The reservoirs in Parque das Conchas are up to 20 km apart. Shell developed special umbilical cables to keep the power supply running and to feed chemicals to the seabed production system. The 25 centimetre-wide cables also carry sensors that convey vital temperature and pressure information back to engineers on the surface. The six cables, which stretch for a total of 54 km, supply electrical and hydraulic power to the wells, manifolds and pumps. The chemicals prevent frozen solids forming in the oil.
Steel pipes that bend
Phase 1 Project Manager Kent Stingl revealed how technologies met ultra-deep-water challenges
Title: Kent Stingl, BC-10 Project Manager – from YouTube
Duration: 5:00 minutes
Description:
Interview with Kent Stingl, BC-10 Project Manager, and tour of the Espirito Santo and BC-10
Kent Stingl, BC-10 Project Manager – from YouTube Transcript
[Background music plays]
Uplifting music
[Video footage]
A Shell oil truck drives by. Montage of Shell employees.
[Text displays]
Shell People
Interview with Kent Stingl
BC-10 Project Manager
[Kent Stingl]
My name is Kent Stingl and I’m the BC-10 Project Manager.
[Text displays]
Kent Stingl, BC-10 Project Manager, Shell Brasil
[Kent Stingl]
I’ve been associated with the project since 2004.
[Video footage]
Helicopter fly-around of the Espirito Santo vessel at sea. There are two smaller ships close-by.
[Kent Stingl]
BC-10 is about 120 kilometers southeast of the city of Vitoria. It’s in the northern Campos basin. It’s a relatively new area, not only for Shell but for Petrobras as well.
[Video footage]
We’re approaching the Espirito Santo vessel by helicopter. We can see the helideck aboard the vessel as the helicopter prepares to land.
[Kent Stingl]
The water depth is about 2,000 meters at its deepest at the Abalone Field. It’s ultra-deep water. We’ve been deeper, but each time it comes with a new challenge. It’s a relatively benign area, in terms of there’s no hurricanes or monsoons, but there is a constant swell in that area and that constant swell is something that we had to incorporate into the design of the FPSO and into the risers and umbilical’s to be able to overcome.
[Animated sequence]
Animation of Shell employees, dressed in red with white helmets, walking aboard the vessel where we can see the infrastructure of pipes and risers. Then back to interview with Kent Stingl.
[Kent Stingl]
BC-10 is a technically very challenging project. It’s the first one that we’ve actually taken from the exploration phase all the way to the production phase in Brazil. It has a variety of different reservoir properties, small to medium-size reservoirs, so not one big accumulation.
[Video footage]
Side-facing shot of the sign with the vessel’s name, FPSO Espirito Santo, printed in black letters on a white background.
[Kent Stingl]
We need to tie those together and make it an economic proposition.
[Video footage]
A Shell employee is standing on the deck of the Espirito Santo with his back towards the camera. He is wearing a red jacket with the Shell logo and the words Shell Brasil E&P written across it. Turning to the side, we get a glimpse of a ship approaching the Espirito Santo.
[Kent Stingl]
We used an FPSO solution because we’re 120 kilometers offshore Brazil and we have a very heavy oil regime. So we have heavy oil and it has lots of minerals in it, so we needed to be able to capture the hydrocarbons, store them, and then be able to transfer those to a ship where a tanker can come by and then take those and sell them at a refinery that can actually process those heavy oils.
[Video footage]
Overhead shot of the Espirito Santo’s infrastructure, showing various exhausts, cranes, and pipes. A ship approaches the Espirito Santo. Then back to interview with Kent Stingl.
[Kent Stingl]
The FPSO is actually a 1975 vintage Japanese crude carrier that spent the first 20 years of its life carrying crude around the world, and then it actually was an FSO, which is a floating storage and offloading vessel, offshore in Nigeria. And when we got it, it was in relatively bad shape so we had to convert that vessel.
[Video footage]
Time-lapse of the Espirito Santo being approached by various floating cranes and other machinery to commence the restoration work.
[Kent Stingl]
We had to replace all the tanks and for collision resistance, since most of the new vessels are actually double haul, we decided to put what we call sponsons on them, on the sides of it.
[Video footage]
Time-lapse of sponsons and steel being put on the sides of the vessel. Further restoration work is done to the vessel in a port.
[Kent Stingl]
So on the sides of the vessel we have 13 sections of impact resistant steel that go on the side which essentially duplicate what a double-haul vessel looks like nowadays.
[Video footage]
The Espirito Santo leaves the port.
[Kent Stingl]
This is one of the deepest FPSOs in terms of water depth anywhere in the world. At 1,780 meters it’s an extremely deep water development.
[Animated sequence]
Animation of the subsea infrastructure. We can see a floating platform at sea-level with various umbilical’s reaching down where they are fastened to the seabed.
[Kent Stingl]
On the subsea infrastructure, again, we had to combine the subsea pumping and artificial lift system.
[Animated sequence]
Development of the subsea infrastructure. We can see various constructions such as reservoirs and pumps being added to the site which are all interconnected.
[Kent Stingl]
That’s an absolute first. It’s the first full field development where we’re using subsea separation and artificial lift to optimize the production and ultimate recovery from the reservoirs.
[Animated sequence]
360 degree shot of the entire subsea system. Pan up following the umbilical’s up to the sea surface where they enter the vessel.
[Kent Stingl]
The subsea system is all-around flow assurance. How can we produce the hydrocarbons and how can we keep them flowing without them freezing, without having wax precipitation problems, and how can we boost the pressure? So we need to boost what nature normally offers us. So instead of having an aquifer support that pushes the oil through the rock, we need to be able to pump that hydrocarbons up to the surface.
[Animated sequence]
Underwater shot of the subsea system. Zoom in on the pumps, in white, showing the flow of oil.
[Kent Stingl]
But the pumps themselves are not very efficient when you have gas fractions in the oil and in the water, so you want to be able to separate the liquids from the gas.
[Animated sequence]
Sequence showing the gas being separated from the liquids. The flow of gas is illustrated in green, and the oil in red. We can see the two flowing through the pumps and being separated.
[Kent Stingl]
And then you could have the gas free flow back naturally up to the FPSO and then you can pump just the liquids themselves, and that’s the most efficient use of the pumps that we have.
[Animated sequence]
Underwater shot showing the liquids, in red, and the gas, in green, being pushed through the pumps all around the subsea system.
[Video footage]
Interview with Kent Stingl.
[Kent Stingl]
Well, we had up to 5,000 people working on the project on any given day during the execution phase, primarily in Singapore where we had around 3,000 people at our peak fabricating the top sides, installing the top sides, and commissioning all of the hull systems. So a huge team, a global team. We had people in Brazil, we had people all over the world working on the project, so one of the big challenges was trying to coordinate all these activities across a 24-hour time zone.
In the United States, we manufactured the electrical submersible pumps and we fabricated the umbilical’s. In Europe, we fabricated the tubes for the umbilical’s themselves. In Colombia, we fabricated the copper cores that went inside the umbilical’s. We actually moved our team, our FPSO team, from the United States to Monaco where they stayed for one year to do the detailed design work, and then took that same team and moved them over to Singapore where they were there for the fabrication and commissioning of the FPSO themselves.
The execution of BC-10 on time and on budget really proves to the world and everyone in Brazil that we should be, or we can be, the preferred operator.
The constant swell of the ocean posed another challenge. Shell designed risers — pipes that connect the equipment on the seabed to the surface — that can move with the swell. They are rigid steel pipes several kilometres long with a bend which flexes when the sea level rises and drops, helping to prevent fractures and metal fatigue.
A floating production, storage and offloading vessel (FPSO) receives the oil at sea level because of the remote offshore location of Parque das Conchas, a long way from other producing oil fields and established pipelines. Building a platform or new pipeline network would have been too costly.
The Espírito Santo is among the FPSOs moored in the deepest water in the world. It is as long as seven Olympic-sized swimming pools and as tall as a 33-storey building. It is a former crude oil carrier refurbished to include new tanks and collision-resistant buffers around the vessel. The Espírito Santo has the capacity to generate 68 megawatts of power — equivalent to the peak output of about a dozen heavy diesel-electric locomotives — to supply the deep-water oil and gas separation machines and high-pressure pumps on the seabed.
While most equipment used on the seabed was built in Brazil, the project’s submersible electrical pumps and umbilical cables were built in the USA, tubes for its cabling were manufactured in Europe, and the cables’ copper cores were made in Colombia. The FPSO was built in Singapore. At peak, some 3,000 people worked on the FPSO at the Keppel Tuas shipyard in Singapore before it set sail in 2008 on a 16,700 kilometre journey to its final mooring in the Campos Basin.
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