Gas began flowing earlier this year from BP’s liquified natural gas (LNG) project offshore the West African coastline where Mauritania meets Senegal. The project is one of the deepest offshore developments on the continent, bringing gas from water depths of 9,350 feet to a floating production storage and offloading vessel, or FPSO, about 25 miles offshore.
The site is one of two large-scale projects where Emerson is partnering with BP to deliver remote connectivity via its DeltaV Automation Platform to offshore sites for remotely managed operations, said David Mason, BP’s lead control and instrumentation engineer.
Mason and Raul Mercer, Emerson’s BP global strategic account leader, discussed the UK oil giant’s progress toward remote operations during a session at the Emerson Exchange 2025 conference in San Antonio May 21.
The benefits for hard-to-access environments like deepwater oil and gas operations center primarily on enhanced safety by reducing personnel exposure to hazardous offshore conditions, along with significant cost savings from eliminating expensive logistics, Mason said.
“We can bring specialists in when we need to,” he said. “They don't have to travel offshore.”
Implementation process
BP’s adoption of the DeltaV Automation Platform for remote operations began in 2014 at its West Chirag platform as part of the Azeri-Chirag-Gunashli (ACG) field in the Azerbaijan sector of the Caspian Sea. ACG has seven offshore platforms, with the most recent, Azeri Central East, achieving first oil production in 2024.
At West Chirag, the company was running its DeltaV distributed control system and safety instrumented systems (SIS), servers, switches and a central control room offshore. Onshore was an engineering server and integration with terminal systems.
BP has the advantage of running its own private network from its offshore platforms, which means it can extend remote capabilities horizontally to onshore locations.
Horizontal connectivity simply means an operation extends the control and safety network from its main, central location to a remote site. This is ideal for real-time remote process control operations. A horizontal architecture offers low latency, but it’s significantly more expensive to deploy, said Mason.
A horizontal deployment also requires several telecommunications considerations, including corporate standards for network segregation, the media type (fiber or radio) and redundancy requirements with primary and secondary networks traveling down different routes.
“So you’re extending the DeltaV control network and the DeltaV SIS network from one location to another location,” said Emerson’s Mercer. “If you do that, you are obviously on exactly the same network and, therefore, it’s very good for the real-time applications. If you want to move your operators from A and put them in B, then this is the sort of applications that you should be considering.”
Other remote processes, such as reliability and maintenance monitoring and remote engineering, are more suitable for vertical configurations, which involves moving connectivity up through firewalls and other connection points to an enterprise system.
The company’s other field in Azerbaijan is Shah Deniz, which consists of two offshore platforms. When BP extended remote connectivity to this site in 2018, the company expanded the amount of onshore remote monitoring capabilities beyond what it had originally initiated at ACG. This includes migrating matrix panels, virtual servers and interzone server onshore and then bringing those same remote operating capabilities to the Azeri Central East platform in 2024.
In Mauritania, the company is taking a slightly different approach, opting for a vertical deployment. The project, called Greater Tortue Ahmeyim, involves gas processing on the floating vessel where water, condensate and other impurities are removed before exporting the gas about 22 miles via a pipeline to an inshore terminal. The LNG then moves to a carrier for export.
For this particular project, vertical networking made more sense since the company was looking to perform remote engineering functions to enable system modifications offsite. Here, the company is using VXLAN network extensions, which creates some latency, but the goal was to take as much of the Emerson team off the platform as possible, Mason said.
Lessons learned
Both Mercer and Mason stressed the importance of defining the purpose of remote access before embarking on a project because that will determine whether it’s a horizontal or vertical deployment.
“Be clear what you want to do because that might influence your choice of technology as well as how and what you connect it to,” Mercer said.
Other key lessons that Mason cited include the need for a clear statement of requirements for remote access, such as user requirements, emergency response procedures, digital security and maintenance contract requirements.
Mason also stressed the importance of getting the telecoms team involved early in the process. That’s because there are multiple communications systems involved, especially in an offshore environment, including radios and marine radar.
“DeltaV was just one small part of that whole piece,” he added.
