The latest generation of portable dew point analysers has come a long way since the Bureau of Mines type dew point testers described by Deaton and Frost in 1938. Modern instruments are much easier to handle, offer a range of functions, and incorporate design principles that improve the reliability of measurement results. State of the art portable analysers not only make field testing more accurate and less time consuming, but can also serve as an extremely useful and convenient tool for confirming the results of permanently installed dew point analysis equipment. They also provide service personnel with a very useful tool when diagnosing problems.

A growing need for analysis

An online report from the US Energy Information Administration (EIA) dated 12th April, 2012 stated that global consumption of natural gas had doubled between 1980 and 2010.¹

In order to meet this dynamic growth in demand, the infrastructure required to process raw natural gas into a clean burning fuel and then deliver it to end users is undergoing unprecedented expansion. New construction projects can be found in virtually every corner of the world, from new long-distance pipelines in central Europe, the US, and China to LNG plants in Greece, Mozambique, Canada, and Australia. New extraction, processing, and distribution capacity means that there is also a pressing need for additional gas storage facilities.

Until recently, one of the main uses of natural gas has been for heating residential and commercial buildings. This means that natural gas has traditionally been considered a seasonal fuel, in other words, the demand for gas has been significantly higher during the winter months. Because natural gas can be stored indefinitely, the excess supply delivered during the summer is stored until needed to meet demand during the winter. In addition, storage facilities can be located near market centres that do not have a ready supply of natural gas from local reserves.

Today, however, the demand for gas during the summer months is increasing. This growth is being driven in part by the trend to use natural gas to fire electric power stations. The increased use of air conditioning to fight summer heat means an increased load on the electrical supply. As a consequence, power plants are consuming more fuel than they used to during this period.

But the weather in many places is fickle. As people turn their air conditioning on and off, power consumption fluctuates. The latest gas turbine power plants can be quickly shut down or brought online to balance out these fluctuations. Because of their quick response times, these state of the art gas fired plants are seen as an essential part of the modern power grid. But this means that gas storage facilities must also be flexible enough to cope with irregular usage patterns.

Storage options

Natural gas storage takes one of two forms. LNG stored in tanks above ground and natural gas stored in underground reservoirs. These reservoirs in turn fall into three categories: depleted gas reservoirs, aquifers, and salt caverns. Of these three types, depleted reservoirs are usually the least expensive. They are the easiest to develop, operate, and maintain and are therefore the most commonly used type of underground storage. Depleted reservoirs are geological formations from which the recoverable raw natural gas has already been extracted. Not surprisingly, this leaves an underground formation that is capable of storing a large volume of gas that has been processed for delivery.

Aquifers are naturally occurring subterranean permeable rock formations that are saturated with water. In specific situations, an aquifer can be used for natural gas storage. However, this type of facility is more expensive to develop than a depleted reservoir, so aquifers are usually only used in areas where depleted reservoirs are not readily available.

Underground salt formations can also be used for natural gas storage. When a salt deposit is located and deemed suitable for natural gas storage, a cavern must be created within the formation. Essentially, a hole is bored into the deposit and then water is injected to dissolve and extract a certain amount of the salt. This leaves a large empty space. Salt caverns are well suited to natural gas storage as they allow very little of the injected gas to escape unless it is deliberately extracted. In addition, the walls of a salt cavern are very robust. This means that this type of reservoir is very resistant to degradation over the life of the facility.

Salt caverns are also used for oil storage. As consumption patterns shift, some salt caverns are being converted from storing oil to storing natural gas. But this type of repurposing for existing facilities can pose certain problems. This is especially true when the reservoir in question is used to store gas that has been fully processed for delivery.

Problems for processed gas

When it is first extracted from the wellhead raw natural gas contains a number of hydrocarbon and non-hydrocarbon gases. The main constituent of this gas is methane (C1), but there are also other hydrocarbon gases. These may include ethane (C2), propane (C3), butanes (C4), pentanes (C5), hexanes (C6), heptanes (C7), octanes (C8), and nonanes and above (C9+). The C number after the name of each gas refers to the number of carbon atoms in a single molecule of that compound. At C1, methane (pure natural gas) is the lightest.

The non-hydrocarbon gases can include nitrogen (N2), carbon dioxide (CO2), helium (He), hydrogen sulfide (H2S), water vapour (H2O), oxygen (O2), other sulfur compounds and trace gases.

Water in gas poses particular problems. Water vapour can condense and combine with the hydrocarbons to form clathrate hydrates. These are structures in which methane molecules are trapped within a lattice of water ice crystals. Clathrate hydrates can cause a number of problems. In addition, CO2 and H2S form corrosive compounds in the presence of water. Because N2, He and CO2 do not burn, and thus have no heating or caloric value, they are referred to as diluents.

All of this means that raw natural gas has to be processed to remove: virtually all of the water; those constituents that have no calorific value; and the heavier hydrocarbons that will liquify at too high a temperature. Because the gas that is to be delivered for use must conform to specific standards of purity, quality control is a critical link in the delivery chain.

Since hydrocarbons and water vapour are both subject to condensation, their dew point properties can be directly measured. As a consequence, dew point analysis can be employed to establish concentration levels of these gas constituents. There are several methods for measuring dew point. As the condensation properties of water vapour are different from those of hydrocarbons, not all methods are suitable to measuring the dew point of both substances. One type of analyser that does work well for both involves the use of a chilled mirror. This type of instrument is designed in such a way that the natural gas is exposed to a mirrored surface, either by placing it in the flowing gas stream or within a closed chamber filled with a gas sample. Dew point can be established by repeatedly raising and lowering the temperature of the mirror and noting at what temperature condensation begins to form on its surface.

Several companies have developed technology that makes use of the chilled mirror principal. Each of these technologies relies on a slightly different aspect of the condensation process. This means that analysers from different companies often produce slightly different dew point results unless they are individually calibrated to correspond. When two different entities in the gas delivery chain have divergent dew point values, it is a problem. The best solution would be to establish a method of standardization in order to minimize these discrepancies.

Recently, Open Grid Europe carried out the GERG Project² to address this issue. Two modalities for eliminating measurement discrepancies were tested and compared. The results of the GERG Project indicate that by calibrating all of the analysers to register a dew point that reflects a saturation level of 5 mg/m3 the discrepancy between measurement values is reduced to a range of 3 – 8 K.

Flow through type analysers (Figure 1) are often preferable as they most accurately reflect the quality of the gas under operational conditions.

Figure 1 A permanently installed Cong Prima-2M automatic dewpoint analyser.

Because essential information about gas quality can be gained through dew point analysis, specifications for the dew point of water (WDP) and of hydrocarbons (HCDP) are included in natural gas regulations. Dew point values are also stipulated in the contractual agreements between entities in the gas industry. In Europe, standards for these values have been developed by EASEE-gas. This is an organisation that was set up in 2002 to promote the simplification and streamlining of both the physical transfer and the trading of gas across Europe.

Because heavier hydrocarbons can condense into a liquid state while methane remains in a gaseous state, natural gas with a high percentage of heavier hydrocarbons is referred to as wet gas. Somewhat confusingly, gas that has a high water vapour content is also commonly referred to as wet gas, but the context usually makes the specific meaning clear. After the water and a significant percentage of the heavier hydrocarbons have been removed through processing, the gas is referred to as being dry.

But a problem can arise when natural gas is stored in salt caverns that were previously used to store oil. Because processed gas is so dry it will tend to absorb any residual heavier hydrocarbon molecules left over from the oil. Even though these storage facilities are thoroughly 'scrubbed' before the gas is injected, it is virtually impossible to make them clean enough to prevent any absorption of heavier hydrocarbon molecules from taking place. In other words, the gas is dry when it is injected into the reservoir, but it has gotten a little wet by the time it is extracted again. Even though the number of these heavier molecules is small enough not to effect overall gas quality per se, they can cause problems in terms of dew point control.

Case study

Recently, a gas supplier developed new storage capacity by opening up new salt caverns while also repurposing existing caverns that had been used to store oil. Following standard procedure, the gas was subjected to dew point analysis when it was extracted for delivery. There was nothing unusual about the flow of data coming from the automatic dew point analysers checking the gas being extracted from the new caverns, but the data about the gas flowing from the old oil caverns revealed puzzling anomalies. Every so often the hydrocarbon dew point temperature would increase for a period of time only to go back down again. The hunt was on to find the cause of this erratic behaviour.

To have a clear idea of what was ultimately behind the swings in dew point temperature it is necessary to understand the issues involved in this type of analysis. Dew point is not only a function of temperature but also of pressure. In the case of H2O (water vapour) this is a linear relationship. This means that, for a given saturation level, as the pressure increases so does the dew point.

Hydrocarbons, on the other hand, behave differently. As the pressure rises so does the dew point temperature, but only to a point. After that, as the pressure increases the dew point temperature actually goes down again. This means that it is possible to have the same dew point temperature at two different pressures. It also means that there is a highest possible dew point temperature that correlates with a specific pressure. For natural gas that pressure turns out to be approximately 27 bar. This pressure is known as the cricondentherm (Figure 2).

Figure 2. Graph depicting the cricondentherm of three gases.

It is understandably desirable to create a situation where only one dew point value is possible, therefore in many installations the gas flow is adjusted to 27 bar for dew point measurement. The reduction in pressure involved has the unavoidable effect of cooling the gas. To prevent premature condensation from occurring, the measurement environment is often heated in order to maintain gas temperature at a level that is well above the dew point.

One of the advantages of chilled mirror technology is that, given the right equipment, it is possible to actually watch the condensation forming (Figures 3a and 3b). In fact, this was the mode of operation for the Bureau of Mines type dew point tester, which was the earliest type of chilled mirror instrument that was used to measure the dew point of hydrocarbons. Those early devices were very cumbersome and required the eyes of a highly skilled operator to get reasonable results. Those models used a refrigerant gas (propane) to cool the mirror, so, along with the delicate analysing equipment, the operator was required to carry a heavy tank of gas to the measurement site.

Figures 3a (above) and 3b(below). The surface of the condensation mirror as

seen through the attached microscope. Figure 3a shows a clean mirror and

Figure 3b shows the mirror's surface after the formation of hydrocarbon condensates.

Fortunately, modern analysers have improved on many of the earlier models’ deficiencies. State of the art automatic units use optical sensors to monitor changes in the reflectivity of the mirror’s surface and thereby register the dew point. This eliminates the need for the continuous presence of a human operator. These new models also cool the mirror electrically employing a Peltier element, thus doing away with the need for costly and cumbersome tanks of refrigerant.

The down side of most of these modern analysers is that they do not make provision for direct visual observation. So, in a situation where the results from an automatic unit are called into question, it is often necessary to temporarily install a portable unit equipped with a microscope. In this way a technician can see what is actually taking place on the mirror’s surface as it cools. This is an important diagnostic ability.

Like their permanently installed automatic counterparts, modern portable models cool their mirrors electrically. The Hygrovision BL from Vympel is an example of a modern full function portable dew point analyser (Figure 4).

Figure 4. The Hygrovision BL portable dew point analyser.

The operators of the storage facility in question were eager to find out what was causing the erratic readings at the repurposed salt caverns, so a service technician from Vympel was called in. The technician used a Hygrovision BL unit to visually monitor the process of condensation in the gas being extracted. The BL provides technicians with several modalities for examining this type of problem.

Firstly, the unit was set up in order to allow direct observation of the condensation process in real time. In this way, an immediate overview of conditions on the mirror’s surface was obtained. Because the BL also has the capability to measure and distinguish between the dew points of water and hydrocarbons, the technician was able to confirm that excess water vapour was not finding its way into the system. It could also be immediately confirmed that the temperature being reported by the automatic instrument coincided with the results observed manually.

Secondly, after the BL’s own automatic readings were confirmed, the analyser was left online to operate in automatic mode for extended periods. Here again this provided a way to corroborate the information being reported by the permanently

installed equipment over hours and days. It is also possible to mount a video camera onto the BL’s microscope, so as a further check, the process of condensation was also recorded over a number of measurement cycles over many hours. The data gathered by the technician using a Hygrovision BL provided the information necessary to understand what was causing the anomalous HC dew point temperatures. It was determined that the culprit at the salt cavern was the presence of heavier hydrocarbons that were introduced into the gas during storage. It was assumed that these heavy constituents were left over from the oil. The heavier hydrocarbons were pooling in the measurement chamber when the gas flow was interrupted. Since, basically, the heavier the hydrocarbons the higher the dew point, these additional molecules were causing the HCDP of the gas to rise. So the problem was largely a consequence of changes in delivery patterns. As gas consumption has become more variable, storage facilities more or less turn the gas on and off as needed.

A secondary issue that was also discovered to be interfering with accurate dew point measurements was the buildup of excess residue on the mirror. This residue was not fully evaporating during the analyser’s ‘mirror cleaning’ cycle. This secondary issue was also likely due to the intermittent nature of the gas flow.

Conclusion

The solutions to these problems were fairly straightforward. They consisted of making adjustments to the calibration of the automatic analyser to compensate for the presence of minimal amounts of heavier hydrocarbons, taking steps to more effectively purge the measurement chamber when restarting the gas flow, and introducing supplemental manual cleaning of the mirror as part of routine operations.

References:

1. Source: U.S. Energy Information Administration, International Energy Statistics. (www.eia.gov).

2. GERG Report: GERG PC1 / Project 1.64 - Installation, calibration and validation guidelines for online hydrocarbon dew point analyzers.