Shell's solution for dealing with the heavy oil at the low-energy BC-10 concession offshore Brazil – caisson separator electrical submersible pumps - is working ‘outstandingly' well according to the field's project manager. Jennifer Pallanich looks at the technology employed on this field and reviews other recent developments at ‘Shell Park'.
Shell's BC-10 development, aka Parque das Conchas (Portuguese for Shell Park), marked one year of production on 12 July 2010. The project, in 1500m-2000m water depths in the Campos Basin, first saw production from the Ostra and Abalone fields and later the Argonauta B West field to the FPSO Espirito Santo. The whole project – which will develop fields named after shells found along the Brazilian coastline – relies on subsea oil and gas separation and pumping.
Kent Stingl, Shell's BC-10 project manager, calls the Ostra field the cornerstone of the development.
To develop the fields with their heavy oil – Argonauta has oil as heavy as 16-17°API oil while the Ostra field comes in a little lighter on the scale at 24°API – Shell planned to use a subsea manifold with caissons with 1500HP electrical submersible pumps inside. Four caissons serve the Ostra and Abalone fields, while two caissons handle Argonauta B West. At Ostra and Abalone, one of those is a backup, and one of the Argonauta B West units is a backup as well.
Caisson ESPs boost the production in reservoirs with a low gas volume, such as Argonauta B West, while separator caisson ESPs will separate the gas from the liquids at fields like Abalone and Ostra, where higher gas volumes could spell decreased ESP efficiency. Both the caisson ESP and the separator caisson ESP are 100m long by 42in with a 32in internal liner. Shell is using Centrilift ESPs.
When the project first went onstream in mid-2009, Shell didn't need to run the ESPs; the initial pressure was high enough that Shell didn't need to provide boost (OE March & July 2008). By February and April 2010, that pressure had eased off enough to prompt Shell to start up the ESPs at the Argonauta B West and Ostra fields. The pump at Argonauta B West has been working for five months, Stingl notes. Since it began boosting in February, the pump has put in about 4000 hours of run time and pumped 1 million barrels of the 16-17°API oil.
The pumps at Ostra, online since April, have been in action for about 6500 hours. ‘They've been on for 3 1/2 months and they're performing outstandingly. We've pumped about 7 million barrels of oil through those pumps at the Ostra and Abalone fields,' Stingl says.
The different gas:oil ratios of the fields call for different production scenarios. For example, the production stream of heavy oil at Argonauta B West keeps the liquids entrained with the gas to prevent viscosity from rising too high and sends the multiphase flow to the FPSO. At Ostra, however, the liquids are separated from the gas before the oil is sent to the FPSO as a single phase fluid.
Stingl attributes the pump performance to continuous monitoring. It's essential, he says, to measure the fluid levels in the caissons to operate the pump effectively. To do so, multiple pressure gauges in the caisson system measure liquid levels. Based on the results, he adds, Shell can adjust the pump speeds to ensure a continuous stream of fluids to the pump and to minimize any liquid carryover in the gas riser.
Also Stingl remains alert for sand production, which is ‘a big potential pump killer'.
At times, Stingl notes, debris has shown up in the chemical injection system and needed to be flushed. That required a few starts and stops. Additionally, he says, the variable frequency drives on the topsides that provide power to the ESPs have had a few hiccups. With BC-10 Shell has seen, he says, more trouble with the ancillary equipment than the primary equipment.
In May, BC-10 hit peak production of 93,000b/d. ‘We're getting more production than we thought the Ostra reservoirs would give up,' he says.
In fact, Ostra was originally planned as a six-well development, but on locating additional reserves, Shell opted to drill a seventh well. As of late July, the supermajor was awaiting the fabrication and subsequent installation of a subsea tree.
The system is nearly at nameplate capacity, and Stingl believes part of the high production rates can be attributed to the quality of well completions. They have, he says, a high output rate with low drawdowns. Just recently, he said in late July, Shell was starting to see the first water production, right in line with when water was predicted to show.
‘When we first put the project schedule and production forecasts together back in 2005, we anticipated first oil right where we were, right in the middle of 2009, and we expected water breakthrough to happen relatively quickly,' Stingl says.
The pumps are pretty much maxed out, he notes, each pumping about 25,000b/d. Early on, they were pumping only oil, but with the advent of water shows, the pumps are now pumping mixes of water and oil.
Shell expects to award contracts for the second development phase at Shell Park later this year. Phase two calls for development of the heavy oil Argonauta O North field with seven producer wells and four injector wells. That's a change from the five producers and five injectors originally planned.
‘So far we haven't changed the development plan at all,' Stingl says, noting ‘we slightly changed the system design layout on phase two'. Those changes followed learning about field partner Petrobras' successes with horizontal well injection. ‘We're comfortable that our field is very similar to an analog of fields they are producing.'
Stingl expects Shell to also begin the execution phase later this year. The field's oil is similar to the 16°API oil found at Argonauta B West.
‘Argonauta O North is going to require water flooding. This will be the first field where we need water flooding,' he says. Shell anticipated needing water flooding with this field, and the FPSO can handle 75,000b/d of water for the water flooding program.
Originally, the thinking was that Shell would use twin screw technology for artificial lift at Argonauta O North, but based on success with the systems in use, ‘we're going to duplicate the nonseparated caisson system that we have at Argonauta B West,' Stingl says.
The changes to the phase two design do not affect the initial production forecast, he adds. Argonauta O North is expected to begin production in 2013.
Shell is considering the possibility of a third phase stemming from exploration opportunities that exist within the block, Stingl notes.
The project itself – operated by Shell with 50% on behalf of partners Petrobras (35%) and ONGC (15%) – has about a two-decade field life, and the risers were designed for 30 years. The SBM-owned and operated FPSO moored in 1780m of water is under a contract for 15 years plus options.
The FPSO's three separate processing trains employ an innovative heat recovery system to break down the oils and separate the water, a process requiring huge amounts of heat. This is recovered throughout the processes, Stingl notes, and the vessel also has what he describes as a ‘pretty significant' 56MW of onboard power to run the ESPs and carry out other activities.
The FPSO is served by a steel lazy wave riser design connecting to an internal turret. Stingl says the decision to use rigid risers relates partly to the fact flexible risers weren't available on the market when Shell needed them for BC-10. The project represents the first use of a steel lazy wave riser tied back to a turret-moored FPSO.
Oceaneering supplied and Subsea 7's Seven Seas installed the high-voltage umbilicals. According to Stingl, these umbilicals take the power generated at the FPSO and transmit it effectively, efficiently and consistently to the ESPs. It's vital that the umbilicals meet all three of those characteristics, he says, because a power fluctuation could harm the pumps. A cross-section of the umbilical shows a copper power cord and hydraulic and chemical lines, so only one large umbilical was needed rather than several.
Stingl says the BC-10 project is tremendously complex because of the reservoirs. ‘We've got to try to connect all these compartmentalized accumulations with horizontal wells,' he says.
‘We've been able to connect a whole lot of smaller reservoirs by connecting through faults.'
The water depth – which ranges from 1500m to 2000m – is about two-thirds of the total well depth, as the wells seek fairly shallow targets below the mudline.
‘It's a long way we've come in the industry,' Stingl says, to be able to do the drilling, boosting, and all of the other efforts involved in making BC-10 a reality. ‘Twenty years ago, the oil in these reservoirs would have been stranded.' OE