In today’s industrial facilities, using reliability-centered maintenance as the primary approach to reduce maintenance costs and operational downtime is more commonplace. This approach may be hindered because most petrochemical facilities were built before this maintenance strategy became a priority. Even today, expansion projects planned to reduce costs often under-instrument equipment at the expense of losing the capability to effectively troubleshoot and predict issues. For rotating equipment, field instrumentation serves three purposes:
- Operators are often required to make decisions based on the parameters measured directly in the field.
- Maintenance and engineering professionals often use gauges to troubleshoot problematic equipment to determine the root cause of failure.
- Instrumentation can predict the causes of poor reliability before repeat equipment failures.
This article discusses the critical issues/parameters that should be managed to maximize reliability, with recommendations to utilize local pressure instrumentation to aid in predictive maintenance and troubleshooting.
Pump Operating Point
Pumps are designed to achieve a specified design flow rate and differential head at which they should operate. Running within 10 to 15 percent of its best efficiency point (BEP) allows the equipment to minimize the vibrations associated with imbalanced internal forces. Note that the percentage off of BEP is measured in relation to the BEP flow rate. As shown in the pump curve in Figure 1, reliability suffers dramatically the farther a pump is operated from its BEP.
Figure 1. Sample pump curve
A pump curve works as a law for where the equipment can operate—if it is undamaged. The operating point of a properly performing pump can be predicted by using either the suction and discharge pressures or the flow rate. If damage to the equipment occurs, all three parameters must be known to accurately measure the performance of the pump. However, determining if any damage to the pump has occurred is difficult without measuring the aforementioned values. This makes the installation of flow meters and suction and discharge pressure gauges critical.
After the flow rate and differential pressure/head are known, plot the two on the graph. The plotted point is likely to be close to the pump curve. If so, how close to BEP the equipment operates can be determined immediately. If the point falls below the pump curve, it can be determined that the pump is not performing according to design and likely has some form of internal damage.
If a piece of equipment often operates to the left of its BEP, it may be considered oversized. Some solutions include trimming the impeller, slowing the pump if a VFD is installed or reducing downstream hydraulic restrictions.
A pump that habitually runs to the right of its BEP may be considered undersized. Possible solutions include increasing the impeller diameter, increasing the pump speed, throttling the discharge valve (if lower flow rates are acceptable) or replacing the pump with one designed to generate greater flow rates. Operating a pump near its BEP is one of the best ways to guarantee a high level of reliability.
Net Positive Suction Head
Net positive suction head (NPSH) is a measure of a fluid’s propensity to stay in a liquid state. At zero NPSH, the liquid is at its vapor pressure or boiling point. Centrifugal pumps have a net positive suction head required (NPSHr) curve that defines the suction head required to prevent the fluid from vaporizing while going through the low pressure point at the eye of the impeller.
Pressure instrumentation can aid in predictive maintenance and troubleshooting.
The net positive suction head available (NPSHa) must be greater than or equal to the NPSHr to prevent cavitation, a phenomenon in which vapor bubbles form at the impeller eye and then collapse violently, resulting in material removal and vibrations that can cause bearing and mechanical seal failure in a fraction of their typical operating life. The NPSHr value on the included pump curve increases exponentially in high-flow conditions.
A suction pressure gauge is the most practical and accurate way to measure NPSHa. Low NPSHa has many different causes. However, the most common are clogged suction piping, a partially closed suction valve and clogged suction strainers. Additionally, operating to the right of a pump’s BEP will increase the NPSHr for the equipment. Upstream restrictions can be identified by installing suction pressure gauges and adding them to operator rounds.
Many pumps utilize suction strainers to keep debris from entering and damaging the impeller and volute. The problem is that they clog with time. As they clog, the pressure drop across the strainers increases, which decreases the overall NPSH available to the pump. A second suction pressure gauge can be placed upstream to be compared with the pump’s suction gauge to determine if the strainer is clogged. If the two gauges do not read equal pressure, it will be obvious that there is a strainer blockage.