Fiscal measurement of natural gas

Oil and gas fiscal measurement accuracy for allocation and custody transfer depends on many factors including measurement technology, fluid quality, rate of production, operating conditions and process complexity.

Fiscal measurement must not be confused with custody transfer; in fact, fiscal measurement is a more general term meaning “measurement for money” that includes both allocation and custody transfer flow measurement.

• Allocation is the numerical distribution of products between parties according to their equity share.
• Custody transfer is contract driven: that means that there is a contractual obligation between buyer and seller which may require adherence to accuracy, repeatability, linearity or uncertainty standards as defined by measurement standards such as API, GOST (Russian equivalent to API), etc. Custody transfer need not imply change of ownership.

Gas custody transfer flow measurement can take place anywhere along the process value chain from the wellhead to delivery or sale location. The dynamics of where these transactions are actually located can be influenced by a number of factors with the two primary ones being regulation and commercial arrangement. However, for the lowest uncertainty in measurement, custody transfer generally takes place at stable, predictable single-phase locations or physical discrete handover points (eg, platform/production exit location, pipeline entry/exit, terminal entry etc).

Natural gas

The natural gas delivered to consumers is composed almost entirely of methane (CH₄). However, natural gas found at the wellhead, although still composed primarily of methane, is by no means as pure. Once separated during initial processing it commonly exists in mixtures with other hydrocarbons, principally ethane, propane, butanes and pentanes. In addition, raw natural gas contains many other compounds such as water vapour, hydrogen sulfide (H₂S), carbon dioxide (CO₂) and nitrogen, along with other impurities. Typical natural gas concentrations for Australian sources are shown in Table 1.

Table 1: Australian natural gas composition (Source: Australian Institute of Energy). For a larger image click here.

Gas gathering systems and major transportation pipelines impose restrictions on the composition of the natural gas that can be shipped into the pipeline. Gas gathering systems usually focus restrictions on the amount of water and other contaminates such as H₂S, benzene, mercury and arsenic. Gas transportation systems, since these are usually after gas processing, generally focus restrictions on quality factors such as CO₂, N₂ and overall Wobbe Index. This normally determines the location of a primary custody transfer point, as quantity and quality must be measured to meet the relevant requirements.

Flow measurement

A complete measurement system is usually composed of many different parts:

• Pressure-reducing lines with overpressure protections, since it is important to stabilise the pressure and maintain it at a constant value to optimise the measurement of the flow rate.
• Metering lines that can include control valves to limit the capacity per line.
• Gas samplers or gas chromatographs (GC) to provide information on gas quality and composition.
• Proving/calibration systems for the periodic checking of the meters.
• A data management and control system.

A large amount of instrumentation is associated with the various steps of the measurement process, and accuracy and reliability are very important to ensure that the overall system uncertainty that has been agreed to within the contract can be achieved and maintained.

Measurement uncertainty

All meters and metering systems are subject to uncertainty and it is a common mistake to confuse accuracy and uncertainty but they are subtly different.

• Accuracy is matching the meter output to a known standard or reference, and will include terms like bias, readability and precision. This can be considered the best estimate according to the scale of the measurement.
• Uncertainty is more related to repeatability, and is an estimate of the limits where the true value is expected to lie for a given confidence level.

Fiscal measurement systems are typically driven by regulation (taxes, royalties etc) and generally follow the same principles as a custody transfer system. A standard natural gas measurement system has an uncertainty of ±1% of energy, and so to get within this value the other system components that combine to generate an energy figure must be better than this.

The main components of a gas measurement system are shown in Figure 1.

Figure 1: The main components of a gas measurement system.

Compression stations (upstream production)

Natural gas is highly pressurised as it travels through a pipeline; as gas is a compressible fluid, the aim is to increase the pressure in the pipelines so more gas can be transported keeping the pipeline size constant. To ensure that the natural gas flowing through any one pipeline remains pressurised, compression is required periodically along the pipe. This is accomplished by compression stations, usually placed at 60 to 160 km intervals along the pipeline. The natural gas is compressed by either a turbine, motor or engine. Siting is dependent on terrain, and the number of gas wells in the vicinity; frequent elevation changes and a greater number of gas wells will require more compression stations.

In addition to compressing natural gas, compression stations also usually contain some type of liquid separator, much like the ones used to dehydrate natural gas during its processing. Although natural gas in pipelines is considered ‘dry’ gas, it is not uncommon for a certain amount of water and hydrocarbons to condense out of the gas stream while in transit.

Pressure reducing

For delivery to the consumers the gas in the main trunk lines is depressurised to manageable levels, and metering lines are usually installed downstream of pressure-reducing stations. This was mandatory years ago when flow computer technology was not so advanced; a constant value of pressure could greatly help to ensure a stable signal sent by the meter. Pressure-reducing lines are composed of a main pressure regulator that will reduce the inlet pressure to a fixed value, and other equipment to ensure overpressure protections: monitor regulators, relief valves and slam shut valves. The choice of the devices used to protect equipment and the pipeline from overpressure problems can be defined by national standards or by customer internal procedures.

Pressure-reducing lines usually include filters and heat exchangers to improve the gas characteristics, eliminating dust, particles and hydrates that could damage downstream equipment.

Meters

There are many different flow measurement technologies available for fiscal measurement; one of the first differentiators is measurement by volume or by mass. Volumetric measurements are called inferential, as these types of meters can calculate the capacity after measuring another parameter, such as the fluid velocity. Examples of volumetric meters are orifice fittings, turbine meters and ultrasonic meters. Direct mass measurement is performed by mass flow meters, such as Coriolis meters.

Even if it’s true that each technology will most certainly work at all given conditions, it is also true that not of all of them will give the maximum performance. The choice of technology to be used will depend on many factors: pressure, temperature, flow rate and range, gas composition and quality, desired accuracy and redundancy, component and installation cost, maintenance cost, required footprint and so on.

It is also necessary to take into consideration other important aspects linked to the characteristics of each meter, such as pressure loss, rangeability, requirements for flow conditioning and the ability to deal with dirty gas or noise in the system. A complete knowledge of gas flow conditions must be understood before the right meter technology can be chosen and the meter station design can proceed.

Odorant injection

Natural gas has no odour so it is mandatory to have it odorised in the event of a leakage, as the ability to smell gas is one of the simplest ways to detect a leak. Odorant injection systems vary from simple and manual ones (ie, absorption type) to complex and completely automated units where concentration ratio is ensured by a microprocessor-based control unit that will keep track of the liquid actually injected and automatically adjust the injection rate to keep the odorant ratio constant.

Gas composition

Knowing the correct gas composition is an important factor in fiscal measurement: it is used to determine the latent energy content of the gas (that is the amount of energy that we will get when we burn it). In addition it is necessary to know if there are any sulfur compounds, hydrogen sulfide and mercaptans (both natural and added as odorants). Contaminants can reduce pipeline integrity, so their monitoring can be combined with energy measurements for complete custody transfer analysis. The physical properties are required for measurement so that quantity can be reported in the required units. Finally, it is important to know the gas characteristics in order to select all the main station components such as filters, heaters, regulators and meters.

There are two main components installed in the field that can be used as an aid in determining gas composition: gas samplers, which collect a sample from the flowing line for transportation to a laboratory for analysis, and inline gas chromatographs, which separate the compounds in the gas and reports the results.

A sampler is normally used where many lines are present, where a lab is readily available and where cost is an issue. A gas chromatograph is normally located on large gas stations with dedicated buyer use. The output may be interfaced to a flow computer or HMI.

Proving and calibration

Periodic calibration of meters is necessary, as their performance can be affected by many things, such as change in physical properties (pressure, temperature, flow rate), mechanical wear, obstructions in the pipe, product build-up and encrustations. For all these reasons, meter performance must be regularly verified to make sure that results are consistent and traceable to an external reference. Meter calibration validates consistent meter accuracy and provides traceable evidence of meter performance.

The simplest and cheapest way of calibration is to ensure mechanical tolerances are compliant with a standard, ie, orifice plate. Another way of calibrating a flow meter is to put it in series with another flow meter of higher accuracy and to compare their readings. A calibrated master meter may be used to measure the flow in a pipe and to calibrate other meters. To achieve a check on the performance of a master meter they are often used in a pair, either in series, so that the consistency of their readings is continually checked, or in parallel, where one is used most of the time and the second is kept as a particularly high-precision meter for occasional checks. Test results are calculated by comparing the reading of the master meter with the meter on test.

Meters can also be sent to external laboratories that can provide calibration services. The third-party calibration facility will normally provide detail of the offset from the reference standard for the meter over the calibrated flow range. This known offset can then be applied as a correction within the flow computer.

Third-party calibration of a gas volume meter is a costly operation, but it is necessary to ensure the high performance required of the meter and to ensure that the system agreed uncertainty can be achieved. One method of reducing such costs is to use a meter that has an advanced diagnostics capability.

Troubleshooting

Flow meters with advanced diagnostics help the operator to be aware of potential problems in the meter and in the sensors (equipment wear, damage). They also help with a number of other events that can occur during operations, in both fluid conditions or in the pipeline itself. As an example, such a meter can help the operator detect problems such as entrained liquids, liquid accumulations, blockage (eg, in the flow conditioner) and pipe coating.

Advanced diagnostics, together with the possibility to set actionable alerts once a specific problem has been identified, will help tremendously by offering an operational insight into pipeline parameters and measurement system health between two consecutive calibrations.

Flow computers

For custody transfer applications, flow computers (FC) are usually mandatory; they measure, monitor and may provide control of gas flow for all types of meters. In volumetric flow measurement, different types of meters will read different gas characteristics — in which case the FC will receive a signal from the meter plus gas temperature and pressure. In many cases, an algorithm is required to convert the reading into a flow rate. Since gas is compressible and affected by temperature, the gas temperature and pressure must also be monitored and compared to a specified standard temperature and pressure within the algorithm.

Mass flow needs to be calculated based on the density of the gas. Since a natural gas stream contains a mix of various hydrocarbon gases of different densities and also some inert gases like nitrogen and carbon dioxide, the gas flow computer will require the entry of mole percentages for each gas component. Mole percentages must be determined via gas sample analysis.

Based on accurate mass flow calculations it becomes possible, based on the energy content of each gas component, to calculate energy flow, since each gas component contains different energy content. Energy flow metering is the ultimate goal, since this is where the true value is for the customer.

In addition to providing volumetric, mass and energy flow data, the gas flow computer also provides date and time as well as instantaneous, hourly and daily data. The gas flow computer typically stores timestamped volume records for up to 35 days in order to provide sufficient time for a host system to retrieve the records as well as to allow time for human intervention if this retrieval fails to occur.

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