The best present is one you didn't know you needed, but once you get it, it becomes an essential part of your life.
The same rule applies to traditional process automation platforms like distributed control systems (DCS), which are acquiring digital tools and software from familiar model-predictive control (MPC) and advanced process control (APC) to more recent Internet protocol (IP) and Ethernet-based Internet of Things (IoT) communications and virtualized computing. These solutions not only enable them to configure, monitor, control and optimize their applications more efficiently and profitably, but also integrate and combine capabilities for accomplishing tasks that previously had to be done separately, if they could be approached at all.
For instance, Columbia Pipeline Group in Houston used to leave 20% capacity available in the nearly 15,000 miles of natural gas pipelines it operates from the U.S. Gulf Coast to the Northeast in case of compressor unit failures at its compressor stations (Figure 1). However, when it increased production to 100% in 2009, CPG had to find another way to maintain reliability, and make sure production wouldn't come to a stop and hinder its contract obligations to its customers in 16 states.
This meant either more pipelines or increased horsepower redundancy on the compressors, as well as better insight into production data and more effective system maintenance. Unfortunately, CPG's homegrown and disparate controls and in-house SCADA were increasingly unsupportable, lacked secure access, and didn't provide enough data or distribute it widely enough to proactively optimize pipeline operations.
CPG management evaluated its long-term needs, developed a five-year plan to modernize controls across all its pipelines, and decided to standardize on one system to improve reliability through added redundancy, enable information-sharing between stations and up to the enterprise level, and simplify long-term maintenance. CPG set a goal of reaching 100% reliability at 100% production by the end of five years.
In many situations, this would be a tall if not insurmountable order with traditional hardware, software and networking, but virtualizing some equipment, software and tasks on servers just might make it achievable.
Speaking of difficult or seemingly unworkable jobs, shifting temperatures, many hours to reach steady state and long dead times make controlling a steam-assisted gravity drainage (SAGD) oil well extremely difficult with a typical PID strategy, so trying to optimize more than 100 SAGD wells might seem impossible. Nonetheless, that's what Nexen Energy ULC and Spartan Controls tried to do at Nexen's Long Lake oil sands facility near Fort McMurray, Alberta.
"These oil sands are highly viscous due to anaerobic bacterial action," says Pranob Banerjee, P.Eng, senior staff APC specialist at Nexen. "This is why we use SAGD, which consists of a 500- to 1,000-meter long steam injection well running horizontally about 5 meters above a parallel producing well in the oil sands layer (Figure 2). The challenge is determining and managing production targets for the emulsion, and bridging the usual 5% gap between expected and actual production, which can add up to 4,500 bpd."
Consequently, Nexen implemented a DeltaV DCS along with a license for its MPCPro module from Emerson Process Management. "Our APC/MPC solution takes controlled variables (CVs) from our wells and plant, and turns them into manipulated variables (MVs) we can use to improve performance," explains Banerjee. "Before MPC, we had a lot of variability, and after MPC, we have a lot less variability."
Banerjee added that employing DeltaV APC was more efficient than other advanced control solutions because MPCPro is embedded at the controller level, and because DeltaV APC blocks are easy to drag and drop. "DeltaV embedded APC has no extra databases, database synchronization issues, watchdog timers, fail/shed logic design, custom DCS programming, interface programming or operator interface development," adds Banerjee. "Typical APC would have taken 10 to 12 months for us to implement, but we added DeltaV APC in just eight months, and installed APC on all our well pads in just six months.
Banerjee added that DeltaV embedded APC and MPCPro allowed it to achieve automated and faster target setting and execution, more efficient target management workflow, better subcool temperature control, improved production rates, and better process interlock handling. "We've also improved our overall emulsion production by more than 9%," said Banerjee. "We've significantly improved control. We now have faster realization of planned targets. We increased operations reliability with reduced pump trips and alarms. It's also easier now for one operator to manage 100-plus wells thanks to improved situational awareness, faster resolution of abnormal situations and increased efficiency."
DCS virtual makeover
Claudio Fayad, software development vice president and marketing director for DeltaV and DeltaV SIS at Emerson Process Management, adds, "The whole DCS paradigm is changing. Digitization and virtualization have been increasing for a long time due to the strength of PCs and servers, but this year is when they really went mainstream, and we saw more hardware replaced by virtual devices, as well as innovative software and better alarms, historians and HMIs. Almost everyone is talking about virtualizing workstations—not controllers yet, but they'll come later because that's the natural path. Users just have to be sure that virtualized control can be reliable."
Fayad adds that high-density I/O cards and electronic marshalling, such as Emerson's Ethernet I/O cards (EIOC) and CHARMs components, respectively, also are reducing the usual DCS footprint, but the hardware-software balance continues to shift more to software. "It's not so much that high-density, digitization or even virtualization are brand new," he says. "We're really just optimizing what's already there, and making DCS architectures leaner and simpler. This allows a fully virtualized system to be set up and start application development in minutes, which reduces costs and makes sure DCS implementation doesn't delay overall projects."
Jim Winter, director of the global process business at Rockwell Automation, adds, "The DCS is traditionally monolithic and bought only in the long-term, but as the IT and operations technology (OT) sides merge, they're putting pressure on the old DCS model. For example, our PlantPAx DCS can also run our Pavilion Technologies MPC module and other key functions at the controller layer, which means better reliability and speed, and more operator mobility because their data can follow them on whatever device they need to use."
Similarly, Honeywell Process Solutions (HPS) is expanding the role of the DCS beyond its usual islands of automation in controllers and electrical systems, and making it the focal point of all control, so it can take on PLC, alarm, safety, power management, historian, turbine control and other functions.
To integrate and unify its Experion Process Knowledge System (PKS) with new solutions such as its Enhanced, High-Performance Process Management (EHPM) software and Lean Execution for Automation Projects (LEAP) initiative, HPS is teaching Experion and its controllers to connect directly with integrated electrical devices (IEDs) so they no longer need to use an electrical control system. LEAP decouples many automation tasks from the physical construction jobs on those projects. This means installation, integration, configuration and testing tasks that used to be done in sequence can now be done in parallel, which saves time and takes much of the risk out of doing them onsite and closer to deadline. LEAP also combines HPS and its UOP division's expertise for new, pre-engineered Experion templates.
In fact, HPS reports it's providing UOP-enabled solutions to Iraq's State Company for Oil Projects (SCOP) at its refinery in Karbala Province, about 120 kilometers south of Baghdad (Figure 3). Scheduled to start up in 2020, the 140,000 barrel-per-day (bpd) refinery will use HPS equipment to accommodate growing domestic demand for products meeting international standards equivalent to Euro V fuel requirements.
"Our solution combines UOP's deep process knowledge with HPS' expertise in plant automation to make the refinery run at the top of its capability," says Mike Millard, vice president and general manager of Honeywell UOP's process technology and equipment division. "Integrating process technology with controls will enable the Karbala refinery to make more gasoline, diesel, fuel oil, jet fuel, liquefied petroleum gas and asphalt, and make it more efficiently."
Honeywell technologies licensed for the Karbala refinery include:
- UOP Penex process to upgrade light naphtha feedstock to produce isomerate;
- UOP fluid catalytic cracking (FCC) process to convert heavy feedstocks from other operations into gasoline;
- UOP CCR Platforming process to convert low-quality naphtha to high-octane components for gasoline;
- UOP Unionfining process to improve distillate boiling-range feedstock quality to help meet specifications;
- UOP Chlorsorb process to meet waste-gas specifications;
- Experion PKS in the refinery's integrated control and safety system (ICSS) to integrate process control, safety systems and automation software in one architecture;
- Safety Manager, which integrates process safety data, applications, system diagnostics and control strategies, and executes safety applications in a redundant architecture;
- Fire and gas safety systems, including SIL3-certified safety systems connected to fire detectors, fire alarm panels, fire suppression systems, gas detectors, sounders and beacons to minimize any abnormal situations; and
- UniSim training simulators to help plan, deploy and manage operator competency.
"Everyone says they can do industrial IoT (IIoT), but the real question is applying it to solve existing manufacturing problems. That's why we developed LEAP," says Jack Gregg, marketing director for Experion at HPS. "These days, process projects are getting larger and more modular, and LEAP employs VMware cloud and virtualization software and our Universal I/O with automated device commissioning to ease project workflows, reduce risk, and take projects off the traditional critical path."
Process control gets on servers
Back at their 15,000-mile, natural-gas pipeline network, CPG engineers decided to standardize on a virtualized PlantPAx DCS from Rockwell Automation, which could share more information across facilities and enterprises, enable remote access, and improve security.
"We were planning to modernize our entire control system across 16 states, and didn't want to be managing multiple points of contact at the same time," says Brian Sloan, automation and electrical engineering manager for CPG.
As a result, CPG installed redundant horsepower for its compressors at strategic points across its network to meet the required pressure for reliable transmission. Programmable automation controllers (PACs) control engine functions. Operators manage individual engine operation via redundant HMIs, and all engine PACs connect to the main compressor station control panel.
This new equipment includes Allen-Bradley Centerline motor control centers (MCCs) with IntelliCenter technology to support auxiliary functions of the compressor station and engine units. The networked MCCs integrate with controllers in the existing system. Motor control components in the MCCs include PowerFlex AC drives, SMC Flex soft starters, PowerMonitor 5000 energy monitors, and E3 Plus electronic overload relays.
When designing the new process control system, CPG realized each station would require more servers than physically possible to handle all applications needed for security, data analytics and system management. The team decided to implement virtualized servers from Stratus Technologies, which reduced the physical space of the hardware, eliminated the need to procure hardware for each new application, and reduced the likelihood of downtime due to hardware errors.
Each of these virtualized servers run multiple Rockwell Software FactoryTalk applications including Historian, View Machine Edition, View Site Edition, AssetCentre and ViewPoint software, which allows CPG operators to access the HMI applications from any location via a web browser. In addition, the historian platform integrates with the corporate-level OSIsoft PI data warehouse system to further increase operational data visibility and availability.
This new, information-enabled system runs on EtherNet/IP, allowing CPG's data to flow easily from engines to the main control panel, MCCs to the PACs, one compressor station to another, and from stations up to the business level. Allen-Bradley Stratix industrial Ethernet switches manage secure, real-time information sharing.
By early 2015, CPG implemented virtualized controls to 40 compressor stations, and reached 99.5% reliability. Also, based on new insights into engine operations, CPG engineers conduct more active and ongoing predictive maintenance, and achieve quicker results. In fact, the company adds it saved about $2.3 million from reduced maintenance costs and downtime in 2014. CPG is already planning to roll out these redundancy upgrades to 52 more stations. Its engineers can use the same system to design any new compressor stations, and they expect their enterprise-wide system to run for at least 10 years before upgrades are needed.
"We're also making more educated decisions based on real-time and historical operations data that we can access anywhere," adds Sloan. "We've been able to significantly improve company profitability as a result."