Unveiling the blind spot

Liquid carryover in gas processing is a significant problem, leading to limitations on gas flow, production losses and increased operational costs due to foaming, fouling, and chemical usage. Liquid carryover in the export gas from gas processing plants, can also lead to higher maintenance costs and serious safety issues at compressor stations, LNG plants and gas turbine power stations. Traditional monitoring systems often fail to detect this problem, giving a false impression of ‘dry gas’. Permanent monitoring systems for phase separation and filtration are currently inadequate. The industry is now adopting real-time monitoring through process cameras to identify issues like mist or stratified flows, thereby improving the balance between processing trains and reducing costs. Traditional gas sampling systems that adhere to API and ISO standards may miss liquid carryover events, leading to financial losses. New process camera systems can capture these events, improving the validation and uncertainty of fiscal metrics like flow and calorific value.

Liquid carryover in gas processing

A detailed survey by Amine Experts studied 400 cases of amine plant failures, finding that these failures cost operators between US$250 000 and US$250 million each.¹ The survey identified three main causes of failure: poor amine quality leading to corrosion; contaminated gas at the inlet causing foaming; and insufficient heat affecting product quality. A notable finding is that two of these main causes – poor amine quality and contaminated gas at the inlet – underline the critical need for better filtration and phase separation at the gas entry stage. Incorrect phase separation was identified as the primary cause (61%) of foaming events.

The survey also points out that many gas plants operate under optimum flowrates to allow a safety ‘margin’ against foaming. Process cameras can bolster operator confidence, enabling them to run plants closer to the optimum flowrates, as these cameras provide real-time data to swiftly deal with issues like foaming. Issues around liquid carryover were also discussed, particularly during the de-sulphuration and de-humidification stages. This carryover can contaminate subsequent processes like NGL removal.

While effective technologies for tackling these issues exist, they are not widely used, affecting the efficiency of NGL recovery and other downstream processes. Contaminants like glycol, which are difficult to detect, are not currently monitored by any custody transfer analysis but are frequently the most common component produced when lines are pigged and have financial implications for operators.

Compressor damage

The survey by the UK Health and Safety Executive found that the average lifespan of dry gas seals, which are usually labyrinth seals with a 5-micron gap between static and rotating components, was significantly shorter than the five years expected by manufacturers and users.² The main reason for this discrepancy was found to be contaminated gas. In every case of failure in the study, liquids were discovered between the faces of the seals. These liquids or solids bridge the gap that is otherwise maintained by gas pressure, allowing for increased thermal conduction and compromising the seal gap. Once the seal components make contact, this results in rapid wear, drastically reducing the lifespan of the seal and, in some instances, causing loss of containment. The cost of each failure was significant, ranging from US$60 000 to US$120 000, not including the loss of production.

Process cameras

The use of process cameras in high-pressure gas pipelines has revolutionised the way operators understand and manage gas flows. These cameras deliver real-time visual insights…

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Read the article online at: https://www.worldpipelines.com/special-reports/09042024/unveiling-the-blind-spot/