Gas analysers are unable to report liquid carryover, and it is an important parameter that is currently not being monitored. It can have a major safety impact and significantly affect the efficiency of both gas processing operations and gas transmission systems. Multiple examples exist where process camera show that liquids exist or a sudden onset of NGLs occur in the pipeline but the hydrocarbon dewpoint system remain stable and does not alarm.
The lack of proper monitoring means that gas processors are allowing valuable natural gas liquids (NGLs) into the gas line and not getting paid for them. The gas transmission system operators do not want to see liquids either due to safety issues and incur further costs to remove them and extra servicing costs on compressors. Process cameras are revealing that the uncertainties associated with calculating hydrocarbon dewpoint are so large that dry gas is frequently being reported while two-phase flow exists in the pipeline. API and ISO standards for the measurement of dry gas do not apply when there is a two-phase flow, but up until recently, there was no way of informing operators when liquid carryover and two-phase flow events occur. Consequently, operators believe that the gas is dry and liquid events go unreported until it is too late, resulting in a process failure or excessive compressor servicing costs and high asset integrity risks.
In natural gas processing, 60% of plant failures are due to liquid carryover at the inlet to the gas treatment process. During treatment, liquids come into intimate contact with gas as it moves through de-sulphuration and de-humidification processes. If not separated, these liquids carry over and contaminate the next stage of the process.
Foaming is a common problem in natural gas processing. It results from liquid carryover at the inlet to the gas treatment plant and poses a significant risk to gas production rates and efficiencies. Foaming can occur when hydrocarbon liquids and other liquid additives come into contact with amine-based liquids used in desulphurisation. A foaming event usually means significantly reducing the process gas flow while de-foamer is added, resulting in lost production, investigation, maintenance, and chemical costs. As a result, many gas plant operators limit the gas flow and run at a rate that is 20%, 30% or even 50% below the design flow rate to ensure a margin in case of foaming. This margin provides an added level of confidence and security for operators, allowing them to react quickly in the event of foaming. By limiting the gas flow, the risk of foaming is reduced, and the likelihood of liquid carryover is diminished. However, this also means that the gas plant is not operating at its full potential, which can negatively impact production and efficiency.
Fouling is a longer-term problem when liquid carryover occurs. When hydrocarbon liquids accumulate in the desulphurisation and de-humidification processes, the high temperature achieved on the re-generation cycle results in carbon levels increasing in the lean liquids returning to the gas processing system. Unless removed with high-efficiency particulate filters, this affects the efficiency of heat exchangers, blocks valves and pumps and can accumulate in gas processing columns.
NGL removal is normally the last process before the gas is exported to the transmission system. It is usually achieved by a pressure drop to reduce the temperature of the gas below its hydrocarbon dewpoint. In a flowing gas, this is the perfect condition to produce a very fine mist flow, the most difficult type of liquid carryover to filter out. If phase separation is not achieved to a high level at these low temperatures, it severely affects the financial benefits of NGL recovery and puts the entire gas transmission system at risk. The operator has the expense of de-pressurising and re-pressurising the gas but not the benefits.
Glycol carryover isnot monitored by any analyser in the current suite of analysers present at custody transfer points, yet it is frequently found when pipelines are pigged. Observations have shown that when liquids are in stratified flow, they move at a very slow speed. The rapid gas flow over the top of the liquid draws off the lighter end NGLs leaving a denser liquid containing glycol, compressor oil, valve lubrication grease and accumulates solids from the pipe wall. The drying process continues moving non-volatile liquids such as glycol and lubrication oil downstream. The liquid turns into sludge and then into a mass of material that is stationary on the pipe wall that slowly dries out until just dry material is left. This permanently reduces the pipe diameter until the flow meter is removed for servicing or calibration. If contamination is still present in the flow meter run, it will quickly contaminate the freshly calibrated flow meter. Just a small amount of contamination will significantly affect the flow meter readings. Just 3mm of contamination will cause a 6” flow meter to over-read by 0.53% ($43K/month at current gas price levels).
It is therefore important for gas plants to have reliable monitoring systems in place that can detect the presence of liquid carryover and contamination. This is where process cameras play a crucial role, providing real-time video and insights into contamination activity in the pipeline and completing the feedback loop required for best practice when controlling any process. Operators can quickly identify and respond to any issues that may arise. Using process cameras, gas plants can reduce the risk of foaming, increase production and efficiency, and ensure that the gas transmission system remains safe and reliable.
Liquid Carryover – Flow Regimes.
The lifecycle of a liquid carryover event is complex. The use of process cameras in real-world, large-diameter gas pipelines has, for the first time, revealed fluid dynamic mechanisms that have led to a greater understanding of how liquids and contamination are conveyed in a pipeline. It is essential to understand these mechanisms to minimise the risk of liquid carryover and the safety issues and loss of profits it causes.
In large diameter pipes, liquids can exist as a mist flow or a stratified flow (a liquid stream at the bottom of the pipe) or both types together. Computational fluid dynamic (CFD) models indicate that stratified flows occur at relatively low gas velocities and that mist flows occur at relatively high velocities. However, real-world observations reveal that stratified flow and mist flow are not purely velocity related. There are many factors including pipe geometry, liquid density, viscosity and temperature that determine whether the liquid is in mist or stratified flow. Operational activities such as a brief drop in flow rate can turn a mist flow into a stratified flow. Mist flows have been observed at very low flow velocities, even stationery gas, and stratified flows have been observed at high gas velocities.
The driving force for stratified flows is friction with the gas and flows have been observed to climb over objects. At high pressure, surprising liquid flow shapes occur in high density liquids e.g. compressor lubrication oil. When multiple liquids are present such as lube oil and NGLs, they can be separate stratified flows within the pipeline.
When a gas is saturated (at or above its dewpoint) and liquids are removed in a phase separator, the gas that remains is still saturated at that temperature and any further temperature reduction will result in liquid dropout and two-phase flow will exist again. In order to achieve the gas quality standards necessary for sales gas, it is essential that low-temperature phase separation at high efficiency is performed to prevent two-phase flow at any point before the gas reaches its destination.
When process cameras are installed, consistent diurnal changes are frequently observed, mist flow increases during the day and decreases at night. It is a stable and repeatable phenomena that exists in both winter and summer. This is contrary to what might be expected. If a gas is close to its dewpoint, mist flow might be expected to start as the temperature drops and the gas hits its dewpoint. However, mist flow density normally increases during the day and reduces at night. This observation is the same when looking at water dewpoints in gas that is transported in over-ground pipework. The gas usually wets by around 5° C during day and dries back to its original level during the night. This is explained by water vapor finding an equilibrium with the pipe wall (and material on the pipe wall). The heat of the day drives water vapor out of the pipe wall and into the gas and at night the reverse process happens. It is therefore considered that when this type of diurnal change is observed in mist flow densities, volatiles are present (normally NGLs in natural gas flows).
During periods of wet gas or two-phase flow, there will be large errors in calorific value measurements, and API and ISO standards for gas sampling and gas quality measurements can no longer be applied to custody transfer measurements as uncertainty on the measurements are too large for the measurement to be useful. Liquids in mist and stratified flows are either not included or removed before reaching the gas analyser and so the measurements represent only the gas phase of what is in the pipeline. Until process cameras were introduced, there was no way of knowing if liquid carryover was present and two-phase flow existed in the pipeline.
Flow assurance and uncertainty budgets for fiscal flow measurements are also important to consider when dealing with liquid carryover. Liquid events can interfere with flow measurements in two ways – by causing dry gas flow meters to read in error, and by leaving operators unaware when two-phase flow is present.
Power Stations. When the gas reaches the power station, a number of factors can increase the likelihood of contamination, including glycol and NGLs contaminating the gas at the inlet, lubrication grease from valve operations, compressor oil leaking into the gas, and iron sulphides collected from the pipe wall. All of these factors contribute to contaminated gas reaching the power station, causing over reading on flow meters used in fiscal measurements and a number of maintenance issues. Contamination and liquid carryover is more likely to be present at startup when gas has been stationery in the pipeline for sometime. At this point the normal pre-heat of the incoming gas is not available and it leaves the turbine vulnerable to damage, including uneven combustion around the turbine, high wear on fuel nozzles, and hot spots on turbine blades.
In conclusion, these safety and financial problems are caused by inefficient phase separation and compounded by gas analyser systems under reporting hydrocarbon dewpoint or non-reporting.
Liquid carryover in natural gas processing is a hidden threat that can have a significant impact on the quality and efficiency of the gas transmission system. By installing a process camera at key points in gas processing and at custody transfer points, single phase flow can be confirmed and results from gas analysers validated. By understanding the causes and consequences of liquid carryover and implementing effective measures, gas processors, TSOs, and power stations can minimize the risk and improve the overall performance of the gas transmission system.