Brazilian operator Petrobras expects to initiate production from a new reservoir to existing facilities in Modules 1 and 2 of its deepwater Marlim Sul field this summer and bring a third module onstream via the P-56 semi early next year. Asset manager Armando Ferreira unravels the complexities of Marlim Sul with Jennifer Pallanich.
The Campos Basin’s 650km2 Marlim Sul field is a pretty complex one, spreading as it does across 22 reservoir blocks.
‘It’s got good sandstones with high permeability and high production, but we have a lot of reservoir blocks,’ explains Petrobras asset manager Armando Ferreira.
‘The main reservoirs are turbidite sandstones, but in 2007, we discovered a carbonate reservoir below the sandstone, and it’s a carbonate layer.’
Marlim Sul and its neighboring fields Marlim and Marlim Leste all have a sandstone turbidite layer as the main reservoir. The trio of fields are ‘very close. They belong to the same geological moment’.
Marlim Sul covers a greater area; the sandstones are thicker in sister field Marlim (Portuguese for marlin, a billfish also known as blue-spotted tuna). Marlim Sul lies in water depths of 800-2600m.
‘The oil in the northern part of the field is different from that in the southern part,’ Ferreira says. The north sector of Marlim Sul has lighter oil in the 24-25°API range, while the south has oil that is as heavy as 13°API. ‘It’s a smooth variation in proportion to the variation in the water depth,’ he adds.
Petrobras’ philosophy is to produce its giant fields in phases, using data gleaned from one or two wells to determine how the reservoir is likely to behave. ‘In each module, we achieve more knowledge about the field and how to develop the next module of the field,’ Ferreira says. A secondary benefit of this approach, he notes, is that it expands the investment phase so the operator doesn’t have to fund the whole field development at once.
Petrobras discovered the field with the RJS-382 well in 1987. ‘At that time, we were still developing the technology to produce oil in this water depth,’ Ferreira says.
The company later carried out three pilot projects. In the first, in 1994, one Module 1 well produced to the P-26 in the Marlim field. In the second, one Module 3 well produced to the small FPSO-2 for about a year, starting in 1998. In the final pilot, two Module 2 wells produced to the FPSO-2 during 2000/01.
‘The greatest part of the reserves are in the first module and second module,’ he says. So far, he says, ‘the average initial production of the wells are 20,000b/d’. One well, he said, started at 42,000b/d and in its eighth year of production was still producing 20,000b/d. Petrobras’ overall production from the Campos Basin weighs in at 1.8 million b/d, and Marlim Sul contributes 240,000b/d of that. Within the year, that level is expected to jump, first when Petrobras brings online a carbonate layer in areas of the field that’ve seen production since 2001 to the P-40 and since 2004 to the FPSO Marlim Sul, and second when Module 3 goes onstream at the end of 2010.
‘Marlim Sul’s a big field,’ Ferreira says. Original oil in place at Marlim Sul was pinned at 11.4 billion boe, with the lion’s share of that – 76% – located in the Marlim reservoir, 17% in the newlydiscovered Carbonate reservoir, and 8% located in the Enchova reservoir. As of early March, 16 exploratory wells, 68 pilot wells and 57 horizontal wells had been drilled in the field. As of early March, the field had produced 590 million boe and held an estimated 2.42 billion barrels of recoverable reserves.
Marlim Sul’s first module began producing in December 2001 to the P-40 production semi; oil is carried via pipeline to the P-38 FSO located about 5km away. The P-40 can process 180,000b/d of oil and 3.8mmcm/d of gas. It can inject 220,000b/d of water. In all, the P-40 serves 13 producers and eight injectors; of the 21 wells, 18 are horizontal and three are vertical. The P-38 FSO has a storage capacity of 1.6 million barrels.
As this field started producing, Ferreira says, ‘we found more oil than we expected. So we have a complementary development of the first module’. Petrobras leased the FPSO Marlim Sul from SBM to handle the additional output from the first module. The FPSO has a production capacity of 100,000b/d and 2.3mmcm/d. It can inject 126,000b/d and serves six producing wells and five injection wells.
Petrobras is leasing Marlim Sul from SBM through March 2012, at which point Petrobras expects to begin producing that portion of the project to the P-40 and P-56. Petrobras has not yet defined where FPSO Marlim Sul will head next.
From the beginning, Petrobras used water injection at Marlim Sul.
In Module 1, Petrobras acquired seismic in 2005 for comparison to pre-production seismic to use in studying the reservoir production behavior. Petrobras plans an additional seismic campaign later this year.
Development work on Module 1 is considered complete, although some infill drilling may still occur, Ferreira says.
Module 2 holds average 22°API oil and lies in 1000m-1400m of water. When it went onstream in January 2009, the field was producing to the P-51 semi, the first platform totally assembled in Brazil; that work was carried out at the BrasFels yard in Angra dos Reis. The P-51 can process 180,000b/d and 6mmcm/d. It can inject 283,000b/d of water. The main project includes 10 producers and nine injectors while the complementary project includes four producers and one injector and the long-term test has one producer in the carbonate section.
‘We have three options to send the oil production from P-51,’ Ferreira says. Once the oil is produced to the P-51 semi, Petrobras can route it to the P-38, FPSO Marlim Sul or the nearby FSO Cidade de Macae via pipeline. The company’s first choice was to route the oil to the Cidade de Macae, but a later discovery outside the Marlim Sul field prompted Petrobras to find an alternative as it decided to free up the FSO Cidade de Macae and its flowlines for production at the new field.
In early March, Module 2 was producing 120,000b/d, taking into account the wells at P-40. The company still has wells to bring online in this module and is closing out development on Module 2.
Petrobras found oil in the aforementioned carbonate section with the Jurara wildcat in November 2007 in the Module 1 area of Marlim Sul.
‘We are lucky because (the carbonate reservoir) is just below the sandstone reservoir, so we can use existing platforms in the field,’ Ferriera says.
Two wells have been drilled into the Jurara reservoir, and plans call for two additional wells. Two Jurara wells are to begin production this year. The first well is targeted to begin production in June to the P-40, with a second well linking to P-51 in April. The final three production wells for the Jurara reservoir will produce to the P-51 (pictured below) when they go onstream in 2013/14.
One well from the Mucua reservoir in the Module 1 area is to begin production OE this August to the FPSO Marlim Sul until that vessel’s contract ends in March 2012, at which point production will flow to the newbuild P-56.
The second planned Mucua well will produce to P-56 when it comes onstream in 2011.
Jurara and Mucua are Portuguese for types of turtles.
The carbonates are expected to produce to the P-40, P-51, FPSO Marlim Sul and P-56. Water injection is not planned, at least initially, at these wells.
‘The carbonate reservoir is very fractured, so we don’t know if it will be possible to inject water,’ Ferreira says, adding in this type of reservoir, the water tends to go into the fracture and leave the oil behind.
The production of this lighter oil to the P-56 in conjunction with the heavier Module 3 oil that it will accept when that module goes onstream at the beginning of 2011 will increase the facility’s capacity. ‘It will help P-56 because this is a light oil, so mixed with the heavy oil will produce better oil,’ Ferreira says, which will not require as much processing time on the platform.
The P-56 semi is slated to leave the BrasFels yard at the end of 2010. A twin of the P-51, P-56 is expected to receive first oil in March 2011. ‘It’s a clone, but the production capacity is not the same,’ Ferreira clarifies. ‘The equipment is the same, but the oil is not the same. The average is 16°API’ in Module 3. Module 2 holds average 22°API oil. P-51 has a production capacity of 180,000b/d while P-56 has a capacity of 100,000b/d. ‘We need more time in the tanks to segregate the oil, gas and water,’ he adds.
Module 3 lies in 1200m-1900m of water. P-56 will serve 22 wells, half of which will be producers. The oil will be carried via pipeline to the P-38 FSO and the gas to P-51.
Module 4 is still very much in the exploratory phase. So far, the company has drilled one well – which turned up 13-14°API oil – and plans appraisal wells. Module 4 is in 2500m of water depth. ‘Probably the oil will be heavier than in the third module,’ Ferreira says. Beliefs are that the rock is likely the same but that the quality of oil will be heavier, based on knowledge gained from the first three modules, he says.
Developing this heavy oil, he adds, will rely on technologies like multiphase pumps at the seabed. ‘We need equipment to pump the oil from this area to the P-51 and P-56,’ Ferreira adds. OE