Draft:Liquid Carryover

Introduction
Liquid carryover is a term used to describe the unwanted transport of liquids such as water, hydrocarbon condensates, compressor oil or glycol in a natural gas, hydrogen, carbon dioxide or other industrial gas pipeline or process.

It is important to understand what is in the pipeline at critical points.

Natural gas processing should ensure that the gas quality is suitable for entry into a Gas Transmission system and will not cause operational problems with the pipeline, compressors or equipment downstream of the processing plant. All dry industrial gases have the potential to become “wet” upon a process failure or poor phase separation. In natural gas processing and transmission, it is crucial to separate the liquid and gas phases for optimal efficiency and safety. However, due to complexities in fluid dynamics, situations often arise where gas phase and liquid phase components are not fully separated, and wet gas or two-phase flows occur, leading to liquid carryover in the form of either mist flow or stratified flow (a stream of liquid on the pipe wall). These circumstances can significantly hamper the operational safety, efficiency, and asset life of gas processing installations.

Challenges and Risks
Liquid carryover is a major concern, accounting for around 60% of plant failures in the natural gas processing industry.

Good phase separation at the front end of the gas processing train prevents hydrocarbons and other liquids from entering the gas treatment plant. If liquids are not properly separated, at the entry point this liquid carryover will contaminate the de-sulphurisation stage, triggering foaming and fouling that lead to unscheduled shutdowns and reduced gas flows.

As the gas moves through de-sulphurisation and de-humidification processes, it comes into contact with large quantities of processing liquid. Amine-based liquids are used in the desulphurisation stage of gas processing to remove both hydrogen sulphide (H2S) and Carbon Dioxide (CO2) from the gas stream, but if good phase separation is not achieved at the exit of the desulphurisation process, these liquids carryover into the de-humidification stage of the gas treatment and contaminate that process. In de-humidification, a liquid desiccant, either Mono Ethylene Glycol (MEG) or Tri-ethylene glycol (TEG), is used to reduce the moisture content of the gas to ensure that the gas is dry enough to meet sales gas specifications. The last stage in the gas processing plant is the removal of Natural Gas Liquids (NGL). Carryover of glycol into this process often causes processing problems by blocking heat exchangers or causing temperature control problems. It should be noted that while glycol is one of the chief components of liquids found when the results of pipelines pigging are analyzed, apart from Process camera, there is no method of determining glycol carryover.

The typical method of extracting NGLs is to reduce the temperature of the gas, forcing it below its hydrocarbon dew point and separating the liquids. However, when temperature reduction is achieved through Joules-Thompson pressure reduction, it creates the right environment for a sub-micron mist flow to form. This type of wet gas flow is the most difficult to filter and requires specialist filtration systems. As the gas warms up, the liquids vaporize, making the vapor phase saturated with respect to hydrocarbons. Liquid dropout in the form of mist flows and stratified flows can then occur with pressure and temperature drops as the gas is transported in the gas transmission system.

Over the longer term, solid and liquid accumulation at low points in the gas transmission system can lead to corrosion to the point of rupture and cause failures at compressor stations, among other problems.

Traditional Monitoring Techniques
Standards from the American Petroleum Institute (API) 14.1 and the International Organization for Standardization (ISO) EN10715, are used to provide guidance for gas sampling for either laboratory or online analyzers of gas streams and provide guidelines for managing high-pressure gases to ensure that liquid dropout does not occur in the sample system as the gas pressure is reduced from the line pressure to atmospheric pressure. It is intended that the sample system provides a representative gas sample to the analyzer and ensures good long-term operation by preventing liquids from reaching the analyzer. Wet gas or two-phase flows are outside the scope of these standards, and therefore, gas analyzers can have large errors and often miss liquid carryover events.

Hydrocarbon Dew point
The hydrocarbon dew point is a critical parameter in natural gas standards. It signifies the temperature at which a hydrocarbon gas starts to condense into liquid hydrocarbon. Hydrocarbon dew point is the combination of multiple hydrocarbon species that may be in the gas. It is, therefore, more complex than water dew point. A popular method of determining hydrocarbon dew point is to use the data from a gas chromatograph to calculate the dew point. However, the many uncertainties in this technique have shown that large discrepancies can occur between the calculated and actual hydrocarbon dew point, thus missing the presence of liquid carryover and the resultant risks it poses.

The use of process cameras in gas pipelines has shown that when a hydrocarbon liquid onset starts, a stratified liquid flow can often be seen, but monitoring hydrocarbon dew point shows no response from the analyzer system.

Impact on Operations
Operational inefficiencies stemming from liquid carryover have both immediate and long-term repercussions. Foaming, which requires a reduction in gas flow and use of de-foaming chemicals, can occur. Over time, these inefficiencies build up, contributing to increased operational costs, compromised safety protocols, and reduced profitability. As a precautionary measure, gas processing facilities may intentionally limit operational capacities, thereby sacrificing optimum gas throughput. For gas processors, errors in Hydrocarbon dew point and BTU determination can lead to $millions of lost revenue, pigging and rectification or rebuild costs.

Transmission System Operators (TSOs) incur high servicing costs on compressors. A survey of gas compressor failures found a service interval for dry gas seals was 1 year 20 days on average compared to the expected 5 years when operating on dry gas. Risks of pipeline rupture and short asset life are significantly increased when wet gas is present. The frequency of pigging is increased along with the associated costs.

As the gas reaches the power station, the likelihood of contamination increases due to factors such as fouling and NGLs contaminating the gas, lubrication grease from valve operations, compressor oil leaking into the gas, and iron sulphides collected from the pipe wall. Even though some power stations pre-heat fuel gas, contaminated gas containing compressor oil or glycol (that are not vaporised), can cause several maintenance issues, including fuel nozzle blockage and wear causing uneven combustion, and hot spots on turbine blades that can take a power station out of service.

LNG plants can also suffer from liquid carryover on the incoming natural gas feed lines. Molecular sieve used to dry the gas to very low levels are contaminated and lose efficiency when liquid hydrocarbons are present. On occasions heavy hydrocarbons, thought to be compressor oil, have arrived in the cold box and cause increases in differential pressure, causing a shorter operational period for the LNG train.

Calorific Value and Flow Measurements
As liquids are removed from the gas sample being analyzed, there can be large errors in calorific value (BTU) during periods of mixed-phase flow, making it difficult to obtain an accurate picture of the fluid stream. This can contribute to lost and unaccounted-for revenues. Gas analyzers can only report on the portion of fluid they are presented with, which means that measurements made at custody transfer points are unreliable when a two-phase flow is present. Process camera systems provide the highest sensitivity to both mist flow and stratified flow to provide operators with certainty about the gas quality and improve the uncertainty of BTU or Wobbe Index measurements.

When liquid carryover is not specifically monitored as a parameter, operators are unaware of either continuous or occasional liquid events that significantly affects the BTU (British Thermal Unit) calculations, leading to inaccurate gas quality measurements.

Process camera systems have observed that when liquid events occur as stratified flow, debris from the pipe wall (iron sulphide and scale) is left as a deposit on the floor of the pipe wall. The rapidly moving gas above the liquid stream, draws off the lighter liquids leaving a sludge that eventually dries out to leave stationery dry material on the pipe that reduces the pipe diameter. When this happens at the custody transfer point, flow computers have an incorrect pipe diameter in the calculation. While the calibration of the flow meter may be correct, small amounts of material (2-3mm) can cause a significant offset (0.2%) and unless continually monitored and accounted for, should be considered in the uncertainty budget for all fiscal measurement flow meters.

The flow uncertainty budgets for fiscal flow measurements need to account for potential errors, as specified by Sarbanes-Oxley compliance. Unexpected liquids in dry gas systems can add a substantial amount to the uncertainty budget for both flow and BTU measurement.

Innovative Solutions
Emerging technologies like gas pipeline process cameras offer a window into real-time pipeline conditions. Developed by firms like Process Vision, these cameras can reveal discrepancies between standard gas quality metrics and actual conditions, including the often-overlooked presence of wet gas. They allow for a more accurate representation of what is genuinely happening inside the pipeline, facilitating timely and effective interventions.

Installing a process camera system validates gas analyzer measurements when there is a single phase flow and alerts operators when a mixed-phase flow is present.