Skip to main content

Troubleshooting Pipeline Steam Condensate

One day an engineering lecturer at school discussed an accident at a nuclear power station. Seawater had entered the cooling pipes of the reactor. He asked the students what would happen in such a situation.

A Dean’s Honor-List student answered that neutron flux from the reactor would irradiate the sodium ions in the seawater salt molecules to create a short-lived isotope of sodium. This isotope would emit low-intensity alpha radiation which lodges in the interstices of the ferrous lattices of the steel alloys of the pipes, creating hot spots or fractures, leading to escape of radioactive seawater to the river.

No, the lecturer replied, the pipes will rust.

In troubleshooting, then, it is best to frst suspect the obvious. Why make things more complicated than they really are? Recognizing that there is an overflowing sink and turning off the water, for example, can save a lot of time that might otherwise be spent trying to mop up the floor. To troubleshoot problems, it is necessary to be aware of the various factors that may have a direct influence the situation.

Here is an example: Condensate samples were taken of steam that was being taken from six once through steam generators (OTSGs) and two heat recovery steam generators (HRSGs) to several dozen well pads each with dozens of individual well pads. Each HRSG turbomachine produced 90 MW so a combined 180 MW with some extra headroom reaching 202 MW for peak loading. The HRSGs of oil producing steam assisted gravity drainage (SAG-D) sites make high-temperature, high-pressure steam. But only high-temperature, lowpressure steam is needed to be injected into the ground to liquefy bitumen for extraction, so it ma kes financial sense to run the steam through turbogenerators.

Steam condensate samples showing different colors from week to week and well pad to well pad.

Above ground pipelines carry steam to the pads and above ground pipelines carry the produced bitumen back to the plant. The bitumen is then treated to separate the oil from the water, gasses, and steam. The steam in a SAGD site is injected into the ground; heat and pressures change the viscosity of the heavy oil that is trapped in the sand and it flows downward by gravity to collection pipes and is pumped out. The gasses are collected and burned in the steam generators to create heat to vaporize the recycled water from the wells and reuse it.

When samples of steam condensate samples were collected from the steam being injected into the ground, the high-temperature, low-pressure steam was run through water cooled coils. The samples were analyzed for pH, residual a mines and conductivity and the samples were also run through an Inductively Coupled Plasma Optical Emission Spectrometer (ICP-OAS) for elemental analysis. Samples are burned in a plasma flame that is 2,000°F hotter than the surface of the sun.

The color of steam condensate samples collected varied depending on the well pad, as well as varying from one week to another. Many different tests were run in an attempt to find a statistical correlation between the changing shades. A volatile acid test was done, based on esterification of the carboxylic acids present. All volatile organic acids present are reported as their equivalent mg/L acetic acid. This led to the discovery that the darker the steam condensate, the higher the presence of carboxylic acids (an indication of potential corrosion). 

This results from this test can be statistically compared to steam generation parameters such as steam qualities, temperature,pressures, carryover, and amine additions for the set points of the steam engines.

This investigation led to further discoveries. This included the causes of scale taken from samples gathered from boiler pigging operations. X-ray diffraction (XRD) analysis done by an electron microscope scan of scale in an HRSG stream fnal pass going to a turbogenerator. Different kinds of scale have varying effects on heat transfer and metal expansion coefcients, as well as vibration

Author:
BY OREST PROTCH
Orest Protch, retired in 2020, has operated and helped commission many types of process plants including in municipal, industrial and at remote oil camps. He now does freelance writing. For more information, oprotch@gmail.com

Labels

Labels:

Comments

Post a Comment

Popular posts from this blog

Why Pump Shafts Often Break at the Keyway Area

By NTS Pump shaft failure can lead to significant downtime and repair costs in industrial plants. One of the most common locations for pump shaft failure is at the keyway area. In this article, we will explore the reasons why pump shafts often break at the keyway and what can be done to prevent such failures. The keyway is a high-stress point (weakest point)  on the shaft, where a key is inserted to transmit torque between the shaft and the pump impeller or coupling. During operation, the keyway experiences cyclic loading that creates a bending moment in the shaft, which is concentrated in the keyway area. Over time, this cyclic loading can cause fatigue failure in the shaft material, leading to a fracture at the keyway. In addition to cyclic loading, other factors can contribute to shaft failure at the keyway. Improper keyway design or installation can lead to stress concentrations or inadequate clearance between the key and keyway . Misalignment or overloading can also cause ex...
Post a Comment
[Read more...]

John Crane's Type 28 Dry Gas Seals: How Does It Work?

How Does It Work? Highest Pressure Non-Contacting, Dry-Running Gas Seal Type 28 compressor dry-running gas seals have been the industry standard since the early 1980s for gas-handling turbomachinery. Supported by John Crane's patented design features, these seals are non-contacting in operation. During dynamic operation, the mating ring/seat and primary ring/face maintain a sealing gap of approximately 0.0002 in./5 microns, thereby eliminating wear. These seals eliminate seal oil contamination and reduce maintenance costs and downtime. John Crane's highly engineered Type 28 series gas seals incorporate patented spiral-groove technology, which provides the most efficient method for lifting and maintaining separation of seal faces during dynamic operation. Grooves on one side of the seal face direct gas inward toward a non-grooved portion of the face. The gas flowing across the face generates a pressure that maintains a minute gap between the faces, optimizing flui...
Post a Comment
[Read more...]

FACTORS IMPACTING COMPRESSOR SURGE

BY AMIN ALMASI. Surge can be a major challenge for turbo compressors. Operation in the surge area will result in instability, exposing the machine to destructive stresses and forces, high vibration, and even serious damage. Surge during shutdown (trip) has been reported for many turbo-compressors. This is particularly possible if the machine operates at high head and low flow, immediately before the trip, when the operating point can move toward the surge line and even pass it during coast-down (when the turbo-compressor reduces flowrate). When a turbo-compressor experiences a serious alarm, an emergency shutdown is usually initiated. But an immediate shutdown could result in a surge. In this case, the surge happens shortly after the shutdown (trip) and at a high energy level. This could be a surge at a high head (operating point could pass the surge line at high head). In many cases, there are advantages to not removing the driving power from the turbocompressor (tripping) immediately...
Post a Comment
[Read more...]