November 2018

Special Focus: Instrumentation and Automation

Improve refinery production and efficiency with asset monitoring

The sheer volume of equipment in a refinery—from vessels, columns, huge structures and mazes of pipes to pumps, valves, controllers and instruments—is staggering.

 Equipment failure at any junction can have a negative impact on overall operations.

A crude unit, for example, might have 30 to 40 different kinds of pumps. It is important to know how each pump functions and if it is fully contributing to the individual production unit and to the overall facility. Multiply that need by 10,000 or 50,000 times for the rest of the plant’s equipment, and a sense can be gained of how large the scope could be for improvements.

As Fig. 1 illustrates, the equipment mix for each unit varies significantly. For example, a crude unit has far more heat exchangers than an alkylation unit, but both are vulnerable to corrosion. Part of this mix is influenced by the volume each unit handles, as well as by the process involved. Processes that are more heat intensive than others require higher heating and cooling capacity.

Monitoring performance and condition.

The main process monitoring and control for a unit is handled by a distributed control system (DCS) or another automation platform. Additional systems support production, including safety, pollution control and plant utilities. While production, safety and other systems are heavily automated, the remaining intermediate systems and ancillary equipment often operate with little to no automated monitoring. Condition checking, if done at all, depends on manual rounds. Given the staffing challenges many companies face, anything built on manual procedures can present difficulties.

Exceptions to this scenario exist. Very large pieces of equipment, or those upon which the operation of an entire unit depends, might have permanently installed monitoring devices to warn of developing problems. However, in most plants, the list is surprisingly short, with the main reason being cost. Adding permanently mounted monitoring sensors around the facility and wiring them back to a central data collection and processing system is simply too expensive.

Using the DCS only as a passthrough for the huge amount data from field transmitters to the historian, or any other ISA-95 Level 3 system, is a waste of machine resources through underutilization of I/O cards, tags, operator effort and engineering time. Add the cost of creating purpose-built human-machine interfaces (HMIs) and analytics tools to make sense of the data produced by monitoring instruments, and it presents an impossible investment for most facilities. However, there is a better way to achieve desired levels of functionality at a lower capital cost.

When using traditional networking methods and monitoring via a DCS, it is often prohibitively expensive to add monitoring capabilities to even one tenth of the equipment listed in the table. Fortunately, new sensing, communication and data management technologies have emerged that can perform these functions far more easily and at a lower cost.

New types of instrumentation, networking and data analytics tools can be used to monitor:

• Pump installations
• Liquid-cooled condensers (heat exchangers)
• Air-cooled condensers (heat exchangers)
• Steam traps
• Corrosion
• Pressure relief valves (PRVs)
• Safety shower and eyewash stations.

In many cases, the data provided by these wireless sensors and instruments does not have to be sent to the DCS, but can instead be sent either directly to maintenance management systems or to data analytics applications. These applications are designed to analyze data from just one type of equipment or asset, making them easy to install and configure.

These solutions can improve overall performance and are neither complex nor expensive, so they can be extended to these kinds of applications. The savings can add up quickly. Better yet, avoiding an unscheduled unit shutdown can often justify this type of monitoring. The operational modes of some of these operating systems are described in the following sections.

Pump installation monitoring.

The largest and most strategic pumps, such as those that pump feedstock into the crude unit, are likely to already have monitoring equipment installed; they are often redundant duplex or triplex installations. However, other pumps in the crude unit and throughout the larger facility should be monitored, as well.

Pumps are maintenance intensive and suffer a failure or some level of degraded operation at least once every 12 mos, on average. They typically run until failure, and operators then switch to a backup or devise a workaround. This practice is problematic since reactive maintenance costs 50% more than detecting and resolving a problem before a failure occurs. Alternative methods using preventive maintenance sometimes lead to unnecessary equipment inspection. The ideal situation is predicting abnormal operation in a timely manner through predictive maintenance.

Pumps can be equipped with sensors to detect problems early so that appropriate action can be taken. Typical points and equipment monitored include:

• Strainer clogging
• Seal fluid pressure/level
• Inlet/outlet pressure
• Vibration
• Bearing temperature.

Devices that can perform all these functions and operate on WirelessHART networks are now available. The approach used to monitor a given pump will depend on its size and configuration, but the range of sensors illustrated (Fig. 2) is typical. It is important to use a multi-measurement approach because a single sensing technology cannot detect every problem.

Some nascent failures, such as clogged strainers or bearing deterioration, can be detected by multiple means. The various sensor technologies tend to overlap, complementing one another by working together to help diagnose problems. For example, increased vibration might be caused by shaft misalignment or by bearing deterioration. If the bearing temperature and noise have not increased, then the technician doing the troubleshooting can verify alignment since it is consistent with the symptoms.

Liquid-cooled heat exchangers.

Obtaining the most efficiency out of a common shell-and-tube heat exchanger (Fig. 3) requires knowledge of what is happening inside of each shell. A given exchanger has heat transfer limitations based on the amount of surface area between the two fluids and the heat conductivity characteristics of the tubes themselves.

Efficiency losses are typically caused by fouling, which can occur on one or both sides of the tube wall, depending on conditions. The challenge is determining where the fouling is occurring, and this is an area where instrumentation and data analytics can help.

In most situations, the process liquid flows through the tubes of the heat exchanger, while the transfer liquid is inside the shell flowing around the tubes. A full instrumentation schematic is shown in Fig. 4:

• The process liquid inlet and outlet have temperature sensors
• The transfer liquid inlet and outlet have temperature sensors
• Measuring differential pressure (DP) across the tubes can spot internal fouling
• The transfer liquid flow may be measured by a flowmeter on the outlet.

The complete installation calls for four temperature sensors and one DP transmitter. For a more advanced solution, a DP flowmeter can be considered.

Air-cooled heat exchangers.

An air-cooled heat exchanger dissipates heat from liquid by transferring it to the atmosphere (Fig. 5). The hot liquid flows through pipes that have fins assembled into panels. Fans draw air through the pipes, carrying out the heat. Many of the same problems encountered with liquid-cooled condensers also apply to air-cooled heat exchangers.

Fouling of the liquid pipes reduces their ability to transmit heat to the outside and reduces overall liquid flow. The air flow can also become fouled if airborne dust, leaves and other debris become lodged in the passages. Monitoring sensors include:

• The process liquid inlet and outlet have temperature sensors
• Measuring DP across the panels can help detect internal fouling
• Cooling air flow may be measured and used to control the fan speed; or, if the fan speed is fixed, reading the negative pressure inside the exchanger with a DP transmitter can determine air flow
• Fan motors are fitted with vibration monitors and bearing temperature sensors.

The complete installation, if necessary, calls for two or three temperature sensors and one or two DP transmitters, plus motor monitors. Like liquid-cooled counterparts, WirelessHART instruments can fill these functions easily and economically.

Corrosion monitoring.

Corrosion and erosion can negatively impact the safe and reliable operation of a refinery’s infrastructure, often with dire consequences. Wireless, non-intrusive corrosion monitoring allows users immediate visibility into pipe thickness, which is the best indicator of corrosion.

A corrosion monitoring app provides further visibility into pipe integrity by monitoring corrosion and erosion rates. Using data from numerous point sensors, the software application provides deeper understanding and immediate notification of problem areas and degrading equipment before leaks or spills occur. This enables the addition of precise amounts of chemical inhibitors and other measures to ensure that pipe replacement will not be necessary prior to the plant’s next turnaround, thereby optimizing operations and improving safety.

Pressure relief valves.

All pressurized systems have a pressure relief mechanism to allow internal pressure to escape before it overcomes the mechanical strength of the equipment. Pressure relief valves (PRVs) come in a variety of sizes and must be matched with the installation and its ability to generate pressure.

PRVs are mechanical and do not need any electronic components to function. Consequently, they do not have any built-in mechanisms capable of reporting their condition or activity. A fully closed valve makes no noise due to pipe vibration because nothing is flowing through it. When the system pressure exceeds the setpoint, the valve opens, releasing the contents of the system, whether liquid, gas or both. This release generates vibration in the pipe surface—noise that an acoustic transmitter can hear and report to the automation system.

By installing acoustic transmitters using WirelessHART, plants can quickly identify if a PRV is releasing, leaking or chattering (Fig. 6). Acoustic transmitters are one of the most affordable types of wireless transmitters and are a low-cost investment because installation is non-intrusive. The transmitters are simply clamped onto the vent pipe, with no need to shut down the process during installation.

After an overpressure incident, reseating can be a problem. If particulates in vessels and pipes are blown out with the contents, some can lodge in the valve seat and keep it from closing entirely, causing a perpetually leaking state that operators call “simmering.” An acoustic transmitter will detect the leakage, even at a very low level.

Some application cases have shown that a leak gap as minute as 0.1 mm (0.004 in.) in a 30-psi PRV can be detected. Operators can tell immediately if a given PRV has fully reseated itself after an incident. Maintenance then decides when to address the issue based on the cost or danger of the product and the volumes involved.

Steam traps.

Steam traps (Fig. 7) are found throughout steam distribution systems and on pieces of steam consuming equipment. They are mechanical to some extent and are, therefore, subject to mechanical problems. They may fail to open, resulting in a steam leak, or fail to close, causing condensate slugs to back up into steam lines.

Most steam traps are monitored on manual rounds, where maintenance technicians look for signs of leakage. Condensate slugs are usually discovered when they move through the steam pipe and damage equipment. Estimates suggest that 18% of the steam traps in a typical large refinery or petrochemical plant fail every year, each causing approximately $16,000 in additional fuel and steam costs.

The same type of acoustic transmitter used for PRV monitoring can be used in this scenario. By installing acoustic transmitters using WirelessHART, plant personnel can quickly identify steam traps that are leaking, working at less than full efficiency, or have failed to open or close. An algorithm is used to identify failure modes (e.g., good, blowthrough, cold, inactive), with warnings sent for malfunctioning units.

Safety shower and eyewash stations.

Companies often call people their most valuable assets, so monitoring the condition of human beings is also important. Safety showers and eyewash stations are scattered throughout process units but are typically unmonitored. A distressed worker reaching a station may need to call for help on the plant radio, or hope to be spotted by a colleague. With a simple WirelessHART valve monitoring device (Fig. 8), the activation and location of a shower or an eyewash can immediately be reported to the control room and to first responders in the plant. This also helps protect equipment, as a leak or spill might be in progress.

Turning data into information.

Implementing the types of solutions discussed in this article will create significant data flows. For example, outfitting 30 pump installations in a crude unit with four new instruments each will create between 400 and 500 new data points, or tags, if the plan is to connect them to a DCS. If operators and maintenance teams cannot interact with this data easily and effectively, then the entire exercise is meaningless.

If a system integrator must be brought in to create new operator interface screens and write code to bring the new tags into the plant’s automation system, this could be a huge expense. Fortunately, it is not a necessary expense because new software applications are available for asset health monitoring in conjunction with WirelessHART and other instrumentation, independent of the plant’s real-time automation system. These apps are easy to configure using predesigned data-gathering functions and analytical models (Fig. 9).

Returning to the pump monitoring example, these apps make simple the identification of abnormal situations, such as a clogged strainer or low lubricant fluid, before an increase in vibration or bearing temperature occurs. Prepackaged analytics evaluate health against unit history and industry norms, and display this information via intuitive dashboards (Fig. 10).

These functions are made possible with minimal configuration effort and no additional loading of the existing automation system. If desired, reporting and alarming information can be transmitted to external systems, such as the DCS, but this is entirely optional.

These apps are easy to use because each is configured for a specific type of asset. Just as there are apps for pump monitoring, there are corresponding apps for other types of assets, and the list is growing. This specialization helps deliver sophisticated analytics without the need to create customized programming. The customization is already built into the platform, supporting fast implementation and ease of use.

Improving KPIs.

Most refineries use key performance indicators (KPIs) to measure performance, as benchmarked against industry-wide metrics. These KPIs are only as good as the data and information they receive, so installing sensors and apps not only improves plant performance as previously described, but can also improve KPIs and, ultimately, plant performance.

Fig. 11 shows an example with a wireless DP installation detecting a clogged strainer on an FCC reactor feed pump. This data would be sent to the maintenance department so that the strainer could be cleaned or replaced, but it could also provide valuable information at a higher level.

Section 1 of Fig. 11 shows what happens when this strainer clogs: DP builds, flow decreases and pump efficiency drops. Left unchecked, cavitation and impeller damage may result. Section 2 shows how a clog would negatively impact FCC unit performance, and Section 3 shows how it would feed up the chain to affect KPIs.

One of the functions of KPIs and other plant metrics is to reflect optimum operational performance, and even a seemingly small problem like a clogged strainer can cause a major unit like an FCC to underperform, thereby negatively impacting the operation of an entire refinery.

The case for pervasive sensing systems.

The refining industry has benefitted enormously from the growth of sophisticated monitoring and communication technologies over the last decade. Many of these technologies involve internal monitoring, such as smart instrumentation, or the ability to provide diagnostic data on other types of equipment.

This pervasive sensing concept is evolving rapidly, driven by changing worker demographics, growth of industrial internet of things (IIoT) concepts, and the declining costs of setting up supporting networks. New technologies under the pervasive sensing umbrella have brought the important tools necessary to improve production efficiencies, while reducing carbon footprint. Pump monitoring and similar applications are examples of how refiners can use pervasive sensing concepts to improve the profitability of their production fleets quickly, easily and economically. HP

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