Some notable heavy oil projects offshore Brazil are entering advanced phases to increase or maintain production. Russell McCulley reports from Rio de Janeiro on the latest developments at three Campos Basin fields – Statoil’s Peregrino, Petrobras’ Roncador and Shell’s Parque das Conchas – where the challenges go beyond the technological.
My commercial colleagues hate it,’ says Shell BC-10 project manager Alvaro Beloso, on the topic of heavy oil. ‘It sells cheap. It’s expensive to produce. But for me, as an engineer, it’s also fun because I get to play with toys that most of my colleagues never get to look at, never get to play with.’
Shell has had ample opportunity to roll out the tech ‘toys’ at BC-10, also known as Parque das Conchas, the heavy oil development in 1800m water depths that went onstream in 2009. Artificial lift was part of the plan from the start, Beloso says; working with FMC Technologies and Baker Hughes, the company developed a subsea separation and boosting system deployed at both BC-10 and the Perdido development in the deepwater Gulf of Mexico. BC-10 also required the development, with Oceaneering, of an integrated umbilical that could supply high-voltage power to the subsea pumps, along with hydraulics, low voltage power and signal. All phase one wells, in the Abalone, Ostra and Argonauta B-West fields, include multiphase flow meters.
Most BC-10 oil ranges from16°-24°API, with one field bearing oil of 42°API ‘with lots of gas attached’, Beloso says.
Shell is deploying much of the same technology for BC-10’s second phase, which was sanctioned in 2010 and is scheduled for first production late 2013. Phase two includes the Argonauto O-North field, where drilling of a planned 11 wells began in April 2012. Phase two will incorporate four new multiphase subsea pumps identical to those used in the development’s first phase, Beloso says. The same goes for the lazy-wave riser system and integrated umbilicals. The engineers’ mantra for phase two has been ‘justify where you’re not going to do the same’, he says. ‘No new design, no new testing, no new engineering – just give me the same, thank you very much.’
Argonauta O-North presents a few new challenges, however. ‘We need water injection in this one,’ Beloso says. ‘In the first three reservoirs we developed, we had a strong aquifer drive. We had enough energy in the reservoir to bring the fluids up, no issue with water injection. The fields could be produced by depletion. Not the case with O-North. O-North has a bubble point that is very close to the original reservoir pressure, which means we don’t have a lot of room to let the pressure in the reservoir decline. We have to start injecting from day one, and we have to make sure that we continue injecting every day, make sure that every barrel produced is replenished by a barrel of water. That’s going to be a true challenge for us from an operational perspective.’
To ensure that the water is injected where it will do the most good, Shell will install an electrical permanent reservoir monitoring system at Argonauta O-North, which Beloso says will be the ‘deepest application field-wide development of 4D seismic'. Additionally, the company is using the Bully II ultra-deepwater drillship on the field, one of two new compact vessels developed in collaboration with Noble Corporation (sister ship Bully I is under contract to Shell in the Gulf of Mexico) to facilitate ‘faster and cheaper’ drilling.
Like phase one’s fields, Argonauta O-North will produce back to the FPSO Espirito Santo, moored in 1780m of water, which has a production capacity of 100,000boe/d and 75,000b/d water. Shell operates with 50% interest; partners are Petrobras (35%) and ONGC (15%).
‘We are not standing still,’ Beloso adds. ‘We are already looking at a potential phase three for the development.’
Meanwhile, work is under way on modules three and four of the Roncador development, which produced first oil back in 2000. The third phase is slated to go onstream 3Q 2013, with module four due for an early 2014 startup, says Eduardo Bordieri, GM for conception and implementation of heavy oil projects at Petrobras, which operates Roncador with 100% interest. The reservoir holds 18°API heavy oil, which will be produced to the spread-moored P-62 FPSO. Pre-conversion of the P-62 wrapped up in October 2011 at Singapore’s Jurong Shipyard; topsides and additional work at Jurong’s Aracruz location in Brazil reached the halfway point this September, on track for first oil in 1Q 2014. P-62 is a clone of the P-54 FPSO, which recently began receiving production from Roncador module two. Modules two and four draw from ‘pretty much’ the same reservoir, Bordieri says, but were split into separate projects because of volumes. The P-62 FPSO, with a production capacity of 180,000b/d and storage for 1.6 million barrels, will be installed in 1600m of water. Module four will comprise 12 producing wells and five injection wells. Petrobras has two drilling rigs on location.
According to Bordieri, module four has ‘pretty much reached the targets that we had’ despite some supply chain issues. His main concern now is ‘the shortage of manpower’, he says. Steady oil prices have helped the project weather such setbacks.
‘The oil has been higher and higher, so the economics are better,’ Bordieri says. ‘I’m happy.’
Heavy oil economics depend on the value chain, says Johan Mikkelsen, the production director for Statoil’s Peregrino development. The project – Statoil’s largest international development to date – went onstream in April 2011. Peregrino is in 100m water depths and contains an estimated 300-600 million barrels of recoverable 14°API oil. Statoil operates Peregrino with 60% interest, with partner Sinochem holding the other 40%.
Statoil acquired the 1.6 million barrel capacity Peregrino FPSO from Maersk earlier this year. The vessel supplies continuous water circulation and provides power to Peregrino’s two platforms. It boasts an onboard power plant capable of generating 72MW to provide heat to separate the viscous oil and water. ‘The water circulation is extremely important,’ Mikkelsen points out. ‘It’s like a conveyor belt taking the oil to the FPSO. If you tried to just pump pure oil, you could be lucky for a while. But I can’t imagine what would happen if you had a process shutdown.’
Peregrino’s signature feature may be its horizontal wells, some up to 2km in length. There are currently 12 wells in production on the field; a total of 30 horizontal producers and seven injection wells are planned. The project’s second phase could include multilateral wells and polymer injection, Mikkelsen notes. ‘We are working quite hard to see if we could benefit from putting polymers into the water,’ he says, noting that Peregrino has ‘a huge IOR potential’. OE