Natural Gas Sampling Technology Conference

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January 26-27, 2011New Orleans, Louis iana

Table of Contents

Conference Program .......................................................................................................A

Acknowledgements .......................................................................................................CInformation

Dr. Darin George .......................................................................................................1 The Chemistry and Physics of Natural Gas Sampling and Conditioning

Fred Van Orsdol .......................................................................................................17The Standards Pertaining to Sampling and Conditioning of Natural Gas

David Fish .......................................................................................................23Spot and Composite Sampling for BTU Analysis Determination and Natural Gas Physical Properties

Matthew Kinsey .......................................................................................................30Sample System Design Considerations for “Online” BTU Analysis

Jay St. Amant .......................................................................................................33Modular Sample Conditioning Systems for Natural Gas Analysis

Dan Potter .......................................................................................................40Measurement of Water Vapor in Natural Gas by Automated and Manual Water Dew Point Measurement Methods

Sam Miller ......................................................................................................51Sampling and Conditioning Natural Gas for H2S and CO2 Analysis

Shannon Bromley .......................................................................................................56Sampling Wet Natural Gas for BTU and Moisture Analysis

Jim Witte .......................................................................................................66Sampling and Conditioning During Loading, Unloading, and Storage of LNG

Brad Massey .......................................................................................................68Benefits of Training Measurement Technicians in the Science of Sample Conditioning and Analysis

Matt Holmes .......................................................................................................71Are company sampling procedures in line with current standards?

Don Sextro .......................................................................................................75 Impact of Incorrect Analysis on Company Profits

Conference notes section located at end of booklet

Natural Gas Sampling Technology Conference

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Program

Tuesday, January 25, 201112:00 - 5:00 Exhibitor set up - Waterbury Ballroom12:00 - 5:00 Packet pick up / late registration - Waterbury Foyer6:30 - 7:15 Social - Armstrong Ballroom7:15 - 9:00 Dinner - Armstrong Ballroom

Wednesday, January 26, 20116:30 - 7:30 Packet pick up / late registration - Rhythms Foyer7:00 - 7:45 Breakfast Buffet - Rhythms Foyer7:45 - 8:00 Opening remarks8:00 - 8:45 Dr. Darin George 8:45 - 9:30 Fred Van Orsdol9:30 - 10:30 Break & Exhibits - Waterbury Ballroom10:30 - 11:15 David Fish11:15 - 12:00 Matthew Kinsey12:00 - 1:00 Lunch - Gallery1:00 - 1:45 Jay St. Amant1:45 - 2:30 Eric Lemmon2:30 - 3:30 Break & Exhibits - Waterbury Ballroom3:30 - 4:15 Shane Hale4:15 - 5:00 Jeremy Knight5:00 - 5:45 Panel Discussion5:45 - 6:45 Exhibits - Waterbury Ballroom

A

Program

Thursday, January 27, 20117:15 - 8:00 Breakfast Buffet - Rhythms Foyer8:00 - 8:45 Dan Potter8:45 - 9:30 Sam Miller 9:30 - 10:30 Break & Exhibits - Waterbury Ballroom10:30 - 11:15 Shannon Bromley 11:15 - 12:00 Jim Witte12:00 - 1:00 Lunch - Gallery1:00 - 1:45 Advances in Commercial Hardware, Methods, Software, Training, etc. 1:45 - 2:30 Brad Massey2:30 - 3:30 Break & Exhibits - Waterbury Ballroom3:30 - 4:15 Matt Holmes4:15 - 5:00 Don Sextro5:00 - 6:00 Exhibits - Waterbury Ballroom

B

ProgramAcknowledgements

Acknowledgements NGSTech would like to thank the following sponsors and exhibitors:

Sponsors:

Exhibitors:

A+ CorporationABB TotalflowAmetek Process InstrumentsCameronEmerson Process ManagementEnDet Ltd.GE Measurement & Control SolutionsJM Test SytemsMustang SamplingPGI InternationalSherry LaboratoriesSICKSpectraSensorsTrace TechnologyWelker, Inc.YZ Systems/Milton Roy

C

THE PHYSICS AND CHEMISTRY OF NATURAL GAS SAMPLING AND CONDITIONING

Darin L. George, Ph.D., Southwest Research Institute®

Abstract

Recent research has led to changes in industry standards for natural gas sampling, such as the API Manual of Petroleum Measurement Standards Chapter 14.1 and GPA 2166. To best apply these standards, users should understand the physical phenomena that can lead to inaccurate samples. This presentation will review the physics of natural gas sampling, including phenomena such as adsorption and desorption, vapor-liquid equilibrium, and Joule-Thomson cooling; the use of the phase diagram as a sampling tool; and results of research on the physics of natural gas sampling that have led to new industry standards.

Introduction

The ability to accurately determine the composition of natural gas streams will become more important to the gas industry as gas quality takes on increased importance. For instance, accurate data on the water vapor content of natural gas streams is needed to identify potentially corrosive operating environments before significant damage to natural gas pipelines can occur. Hydrocarbon dew points (HCDPs) determined from gas analyses will be used as measures of the quality of a natural gas stream and as criteria for assessing compliance with transportation tariffs. Accurate gas quality data will also be crucial to the effective introduction of liquefied natural gas (LNG) and marginal gas supplies into the natural gas transmission network in the near future, and will also be crucial to its efficient use by customers.

Natural gas samples must represent the true composition of a flowing gas stream to avoid unnecessary shut-ins of gas supplies that in reality meet safety and tariff requirements, or to avoid allowing poor quality gas into a transmission and distribution system. Ongoing research funded by several industry organizations has identified several physical and chemical causes of distorted sample compositions, and has led to improved techniques for sampling natural gas streams for hydrocarbon and moisture content. Many of these improvements have been documented in industry standards for natural gas sampling, such as the American Petroleum Institute (API) Manual of Petroleum Measurement Standards Chapter 14.1 (2006) and Gas Processors Association (GPA) Standard 2166 (2005).

It should be remembered that these documented procedures are not “cookbook approaches,” but guidelines to avoid sample distortion. To best apply the methods described in these standards, those who design and use sampling equipment must understand the physical phenomena that can lead to inaccurate samples. To this end, this paper reviews the physics of natural gas sampling, including phenomena such as adsorption and desorption, vapor-liquid equilibrium, and Joule-Thomson cooling. The paper will also explain the use of the phase diagram as a sampling tool, and briefly discuss recent research on the physics of natural gas sampling that have led to these new industry standards.

Physical and Chemical Phenomena Affecting Sample Accuracy

Natural gas streams are routinely analyzed for heavy hydrocarbons, water vapor, hydrocarbon dew points, diluents, sulfur-containing compounds, and other components. The equipment used to analyze the stream can range from on-site manual devices, such as chilled mirror dew point analyzers, to automated devices such as moisture analyzers and gas chromatographs, to sample cylinders used to transport a sample to an offsite laboratory. All these situations have something in common: a representative sample must be extracted from the pipeline and sent through a sample line to the sample container or analyzer. Accurate natural gas sampling requires that the sample removed from the pipeline and analyzed represent the true composition of the flowing gas stream.

Research by Behring and Kelner (1999) listed several fundamental physical causes of gas sample distortion. They note that natural gas is not a pure substance, but a composite mixture of organic and inorganic pure gases. When certain components are preferentially depleted from the sample gas, the integrity of the mixture is compromised, and the sample becomes distorted. Depending on the physical mechanism, it may be the heavier hydrocarbon components, water vapor, or sulfur compounds that are removed from or added to the sample. This section describes several physical mechanisms that can distort gas samples. The next section will describe sampling techniques that can avoid distortion by these mechanisms.

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Adsorption and Desorption of Gas Components at Surfaces

The first mechanism discussed here is adsorption. This is defined as the attraction and “sticking” of gases or liquids to solid surfaces, either through chemical or physical processes (Weast et al., 1985). The reverse process, the release of gas or liquid molecules form the solid surface, is desorption. Note that adsorption is not to be confused with absorption, which is the penetration of a gas or liquid into another body, such as water into the pores of a sponge. Figure 1 shows a simple example of adsorption and desorption of molecules at a solid wall. Often, this adsorbed layer of gas phase molecules is no more than one molecule thick (Gregg, 1961). Adsorption and desorption rates will depend on the type of molecule in the gas stream, and on other variables that will be discussed shortly.

Figure 1. Adsorption and desorption of different molecules at the wall of a sample tube.

Two very different kinds of adsorption are of concern in natural gas sample collection – chemical adsorption and physical adsorption. Chemical adsorption, a chemical reaction between solid surface molecules and gas phase molecules, may not be easy to reverse and can lead to permanent sample distortion. Fortunately, chemical adsorption can be avoided by selecting the proper materials for solid surfaces (tubing, fittings, containers, coatings, etc.) that will not chemically react with gas phase sample molecules. Stainless steel is a common choice for sampling equipment for this reason.

Physical adsorption, however, is a much more persistent problem. Figure 2 shows the response of a real-time moisture analyzer to a sudden increase in the moisture content of the sample stream. In this test (Barajas and George, 2006), an automated moisture analyzer drew gas samples from a pipeline through a stainless steel sample line containing a heated regulator and heat tracing. All equipment in the sample line was heated to 40°F above ambient temperature, and the sample flow rate to the analyzer was at its maximum.

Heated Regulator (110°F)

High Flow Rate (2.1 scfh)

0

5

10

15

20

25

30

35

40

45

50

8:00 8:10 8:20 8:30 8:40 8:50 9:00

Time (Hr:Min)

Mo

istu

re L

evel

(lb

m/m

mscf)

Test StreamReference Stream

8:05 - Switch to Saturated Stream

Gas Saver OffDecember 15, 2005

Figure 2. Response of a real-time moisture analyzer to the introduction of a moisture-saturated sample stream (Barajas and George, 2006).

flow direction desorbed

molecules

adsorbed

molecules

2

After a stream of moisture-saturated gas was introduced at the sample point, the analyzer required 45 minutes to register the true moisture content of the saturated gas stream. The delay was caused by water vapor molecules leaving the stream and adsorbing to the inside walls of the sampling equipment. Because of this, the first sample volume of gas from the once-saturated stream lost some of its moisture content, and the analyzer registered a moisture level less than the true saturated value of the stream. As the walls of the sampling equipment gather more and more water vapor molecules, less and less moisture is drawn from the stream. The moisture adsorbed on the sampling hardware eventually reaches equilibrium with the moisture in the saturated stream, and the analyzer eventually measures the true moisture content of the saturated supply stream.

The process of desorption can also cause errors in sample analysis. In tests where the moisture content of the sample stream changed from saturation to typical custody transfer levels (less than 7 lbm/MMscf), equilibrium by desorption took significantly longer than in cases where the moisture level increased. As before, water vapor molecules clinging to the sample equipment must reach a new equilibrium with the moisture content of the sample stream. Adsorption and desorption will work to bring about this equilibrium, but stable, accurate measurements will only occur after equilibrium is reached.

The example above discusses adsorption and desorption of water vapor molecules, but heavy hydrocarbons and other components of a gas stream are subject to this process also. Thermodynamic conditions influence this equilibrium for any component, since gas molecules have a higher tendency to physically adsorb to solid surfaces at low temperatures and high pressures. Changing the sample stream temperature and/or pressure will tend to shift the equilibrium and adsorb/desorb gas phase molecules until a new equilibrium condition is reached. Similarly, changes in concentration of a component in the gas stream will cause molecules of the same component on surfaces to adsorb/desorb until a new equilibrium is reached between molecules on solid surfaces and the same molecules in the gas stream.

Gas Components Dissolved into Liquids

A similar effect occurs between gas sample molecules and the surfaces of some liquids. Certain liquids can dissolve significant amounts of natural gas sample components out of the gas phase. These liquids may find their way into the sampling system as residue from previous sample streams, or as solvents left behind from cleaning procedures. As a rule, liquid residue with the same or similar chemical composition as components in gas samples will dissolve those components from the samples and distort the sample compositions (Behring and Kelner, 1999).

An example of this for hydrocarbons can be seen in the test results in Figure 3. Samples of a rich natural gas were placed in constant volume (CV) and constant pressure (CP) sample cylinders containing several liquid residues. The liquids included water and glycol left over from displacement sampling procedures, a liquid hydrocarbon (HC) mixture of n-paraffin hydrocarbons and SAE-30 compressor oil, and DuPont Krytox® lubricant. After storage in the cylinders for two to three days, the samples were then analyzed to determine if components had dissolved into the contaminants and affected the sample compositions. The water and glycol liquids did not absorb heavy hydrocarbon components from the samples, and caused no notable distortion of the sample heating value or density. In the tests with liquid hydrocarbon residues, the liquids did absorb hydrocarbon components from the gas, lowering the sample density and heating value by as much as 8%. In the test with Krytox lubricant, it was found that the cylinder seals had previously been exposed to liquid hydrocarbons. This residue was responsible for the sample distortion, rather than the Krytox.

3

Figure 3. The effect of residual liquids in sample cylinders on the density and heating value of 1,500 Btu/scf natural gas samples (Behring and Kelner, 1999). In the test with Krytox lubricant, the cylinder seals had previously been exposed to liquid hydrocarbons, which were responsible for the sample distortion.

As with adsorption/desorption, the amount of a particular component dissolved in the liquid residue will depend on pressure and temperature conditions of the sample in the container and the amount of the component present in the sample. Sample distortion also is possible where the liquids are in a sample line carrying flowing gas. In this case, when the stream pressure and temperature change, the flowing sample will undergo a similar change in composition to that for adsorption/desorption, as the equilibrium between component levels in the stream and in the liquid changes.

Vapor-Liquid Equilibrium

The causes of sample distortion discussed to this point have all involved components of the gas sample coming into contact with another substance, such as equipment surfaces or a liquid contaminant. When causes of adsorption/desorption and dissolution/elution have been minimized, sample distortion can still occur simply due to changes in the physical state of the gas sample itself. This source of distortion is related to the properties of the components in the sample, and under the right conditions, the tendency of certain components (such as water vapor or heavy hydrocarbons) to undergo phase change and condense out of the gas sample. To explain this mechanism, we must first define some key concepts.

Consider a closed vessel that contains a pure substance, with some number of molecules of the substance in the liquid phase and the rest in the gas phase (Figure 4). The amount in each phase is not critical to the discussion. Even if the substance is in a steady state, some small number of molecules of the substance will move back and forth between the liquid and gaseous phases. At a constant temperature and pressure inside the vessel, the number of vapor molecules condensing to liquid equals the number of liquid molecules evaporating to the gas phase. This system is said to be in vapor-liquid equilibrium, since the amounts in each phase remain constant over time. The pressure that the vapor phase of the pure substance exerts on the walls of the vessel is known as its vapor pressure.

4

Figure 4. Example of a substance in a closed vessel in vapor-liquid equilibrium (Mayeaux, 2006).

The relative amount of molecules in each phase depends on the pressure and temperature of the system. Suppose we increase the temperature inside the vessel (Figure 5). This will add energy to the molecules in the vessel, and more molecules will tend to escape from the liquid phase into the vapor state. A new vapor-liquid equilibrium will be reached with a larger number of molecules in the vapor phase, and a larger number of molecules moving back and forth between phases. Once this dynamic equilibrium has been reached, the vapor phase will reach a new, higher vapor pressure. This is because the vapor pressure of a substance is proportional to the relative amount of molecules of that substance in the vapor phase, a principle known as Raoult’s law (Bailar et al., 1978).

Figure 5. Example of a change in vapor-liquid equilibrium for a pure substance with increasing temperature (Mayeaux, 2006).

Now let us consider a mixture containing multiple components, such as natural gas. At a constant temperature and pressure, we will again see vapor-liquid equilibrium, as the number of molecules evaporating from the liquid equals the number of molecules condensing from the gas. Raoult’s law also extends to mixtures containing more than one component, so that the pressure of the vapor phase is related to the number of molecules in the vapor phase. However, the proportionality between the number of molecules in the liquid phase and the vapor phase will not be the same for each component. Even with the mixture at a uniform temperature, one component may have 50% of its molecules in the vapor phase, while another component may have only 10% of its molecules in the vapor phase. If there are equal amounts of each component in the liquid phase, there will almost never be equal amounts of each component in the gas phase over the liquid. Since the gas phase has different amounts of each component contributing to the overall vapor pressure, we say that each component has a different partial

Number of

molecules

vaporizing

from liquid

phase

Number of

molecules

condensing

from gas phase

5

pressure. In natural gas mixtures, the lighter components (methane, ethane, etc.) will have higher partial pressures than the heavier components (nonane, decane, etc.) (Figure 6).

Figure 6. Example of different partial pressures for different components in a multi-component mixture at vapor-liquid equilibrium (Mayeaux, 2006).

Now we extend the discussion of pressure and temperature changes to the case of this multi-component mixture. Because each component has its own equilibrium relationship between amounts in the liquid and vapor phase, pressure and temperature changes will affect each component differently. Lowering the temperature of the mixture, for example, will drive more of the heavier, less volatile molecules into the liquid phase (Figure 7). Since the various components do not condense equally, the temperature drop will change the composition of the gas phase. Similar changes in the gas composition will occur with increases in temperature, or with changes in the total pressure of the gas phase.

Figure 7. Example of a change in the gas phase composition of a multi-component mixture with a drop in temperature (Mayeaux, 2006).

This key concept – that the composition of a gas mixture changes when changes in pressure or temperature affect its equilibrium with a liquid phase – must be kept in mind when avoiding sample distortion.

Phase Changes and the Phase Diagram

While the previous section dealt with equilibrium conditions between gas and liquid, a natural gas pipeline will ideally carry only gas. If the stream to be sampled is completely in the gas phase, then the pressure and

6

temperature of each component in the gas phase is such that it would be completely gaseous if it were a pure substance, not part of a mixture, at the same temperature and pressure. A sufficient change in pressure and temperature during sampling, however, will cause specific components to condense into liquid, changing the composition of the gas phase and potentially distorting the sample composition.

As explained by George and Kelner (2006), the dew point is defined as the pressure and temperature at which specific constituents in a natural gas mixture begin to change phase. For instance, if the temperature of a natural gas mixture is reduced while the pressure remains constant, the temperature at which hydrocarbons begin to condense from the gas phase to the liquid phase is the hydrocarbon dew point temperature. If the pressure of a natural gas is increased while the temperature remains constant, the pressure at which hydrocarbon condensation begins is the hydrocarbon dew point pressure. Similarly, a temperature and pressure condition at which water vapor begins to condense from the mixture is called the water vapor dew point.

These two types of dew points follow different trends with temperature and pressure. When plotted on a graph of pressure versus temperature, the water vapor dew point curve follows a simple curve, with the dew point pressure increasing with increasing temperature. The hydrocarbon dew point curve is much more complex, but is often considered more crucial to natural gas sample integrity during sampling processes. Indeed, the hydrocarbon dew point is perhaps the single most important property to consider in natural gas sampling. If the sample temperature drops below the hydrocarbon dew point temperature, a significant loss in hydrocarbon content can occur, resulting in errors in volumetric flow rate, heating value and other calculated gas properties.

A phase diagram, such as the hydrocarbon phase diagram in Figure 8, describes the phase change behavior of a natural gas mixture. It will be used here to illustrate the effect of natural gas sampling processes on natural gas. Line A-B in Figure 8 is the bubble point curve. The bubble point is reached when an infinitesimal amount of gas appears during a decrease in pressure of a liquid hydrocarbon mixture at constant temperature. Line B-C-D-E is the dew point curve. It represents the range of pressures and temperatures at which gas/liquid phase changes occur with a natural gas mixture. Line D-E is the lower, or normal, dew point curve. Condensation associated with the conditions defined by this curve may occur during a pressure increase, such as when compressing a gas sample from a vacuum gathering system into a sample cylinder, or during a temperature decrease, such as occurs when the contents of a sample cylinder are exposed to cold ambient temperatures.

Temperature (F)-200-180-160-140-120-100-80 -60 -40 -20 0 20 40 60 80 100 120 140

Pressure (psia)

0100200300400500600700800900

10001100120013001400150016001700180019002000

Gas

2 - PhaseRegion

(Vapor/Liquid)

CompositionN2 = 2.05533CO2 = 0.5132C1 = 82.6882C2 = 6.9665C3 = 4.5441i-C4 = 1.1559n-C4 = 1.2856i-C5 = 0.3983 nC5 = 0.2624C6 = 0.0836C7 = 0.0273C8 = 0.0167C9 = 0.0009

MaximumTemp.

MaximumPressureLiquid

CriticalRegion

Bubble Point Curve(Line A-B)

Retrograde Dew Point Curve(Line C-D)

Normal Dew Point Curve(Line D-E)

A

E

D

C

B

Dew Point Curve(Line B-E)

Figure 8. A typical natural gas phase diagram (George and Kelner, 2006).

7

Retrograde condensation is a phenomenon that occurs in many common natural gas mixtures. It is characterized by the presence of two hydrocarbon dew points at a given pressure or temperature. Retrograde condensation can occur during temperature increases at constant pressure or during pressure reductions at constant temperature. The points along line B-C-D represent the pressures and temperatures at which retrograde condensation occurs. For example, in Figure 8, a temperature increase at a constant pressure of 1400 psi from -60°F to -30°F will cross the dew point curve and cause gaseous components to condense. Similarly, a pressure reduction from 1500 psia to 1100 psia at a constant temperature of 40°F will cross the retrograde dew point curve and lead to condensation. Retrograde condensation is a characteristic of natural gases that should be considered both when sampling a natural gas stream and when designing gas sampling systems, since the range of pressures and temperatures of the retrograde dew point curve can be encountered during common sampling processes.

Tests conducted with natural gas sampling methods have shown that allowing the gas sample to drop below the hydrocarbon dew point temperature will distort the sample composition and lead to errors in properties calculated from sample analyses such as heating value and density. The phase diagram shown in Figure 9 illustrates how different processes common to natural gas sampling can cause the temperature of the sampled gas to fall below the hydrocarbon dew point. Path 1-2 represents the Joule-Thomson cooling process that occurs when natural gas flows through a regulator or partially closed valve and undergoes a drop in pressure. Condensation and sample distortion can occur during this “throttling” process, which will be described later in this paper. The cooling can be offset through the application of sufficient heat to the sampling system, as shown by path 1-3. Path 4-5 shows how condensation of a sample can occur if the sample container and its contents are exposed to an ambient temperature below the hydrocarbon dew point temperature.

Temperature (F)-200-180-160-140-120-100 -80 -60 -40 -20 0 20 40 60 80 100 120 140

Pressure (psia)

0100200300400500600700800900

10001100120013001400150016001700180019002000

Gas

2 - PhaseRegion

CompositionN2 = 2.05533CO2 = 0.5132C1 = 82.6882C2 = 6.9665C3 = 4.5441i-C4 = 1.1559n-C4 = 1.2856i-C5 = 0.3983 nC5 = 0.2624C6 = 0.0836C7 = 0.0273C8 = 0.0167C9 = 0.0009

Liquid

Critical

Region

1

2

Path 1-2: Retrograde condensation during throttling to a lower pressure.

No, or not enough heat tracing on sample line.Path 1-3: Heat tracing can offset the coolingwhich occurs during the throttling process,

thereby avoiding condensation.

4

5 Condensationthat occurs when a sampleor calibration standard is

exposed to ambient temperaturesbelow the hydrocarbon dew point

temperature.

3

Figure 9. A natural gas phase diagram showing several common processes in natural gas sampling that can cause condensation and gas sample distortion (George and Kelner, 2006).

At this point, a simple example will serve to illustrate the potential for errors due to phase change of a sample. Assume that a representative sample of a natural gas stream whose composition is listed in Table 1 is captured in a standard 300 cc constant volume sample cylinder. Suppose that the sample is collected at a pressure of 75 psia and at a temperature above its hydrocarbon dew point of 91°F. Then suppose that the cylinder and its contents are exposed to an ambient temperature of 41°F, well below the hydrocarbon dew point (path 4-5 in Figure 9). As the temperature is reduced below the hydrocarbon dew point temperature, hydrocarbon constituents condense, with heaviest components preferentially condensing first. This condensation causes a

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decrease in the vapor fraction of the mixture and a corresponding decrease in the heating value of the vapor phase.

Table 1. The 1,500 Btu/scf natural gas mixture used in the example of Figure 10.

Component Mole percent

Methane 64.107

Ethane 10.33

Propane 7.128

Isobutane 2.174

n-butane 6.386

Isopentane 1.874

n-pentane 2.307

Hexane 0.538

Heptane 0.187

Octane 0.086

Nonane 0.023

Decane 0.016

Nitrogen 3.939

CO2 0.906

Total 100.001

Figure 10 shows the potential effect of 41°F gas sampling equipment on the 1,500 Btu/scf natural gas composition listed in Table 1. The horizontal axis shows the temperature of the gas-liquid mixture. The vertical axis on the left shows the vapor (gas) fraction on a molar basis. The liquid fraction is simply one minus the vapor fraction. The vertical axis on the right shows the change in vapor fraction heating value, in Btu/scf, as liquid condenses from the gas sample. Because the heavier components condense first, Figure 3 shows that a small amount of liquid condensation is associated with a large decrease in heating value. At a temperature of 41°F, the loss in heating value amounts to over 70 Btu/scf.

It should be noted that this is a simple example of the potential problems caused by distortion of a natural gas sample. In practice, the effect of a distorted gas sample on calculated gas properties is very difficult to predict. The effects of poor sampling technique on gas samples taken under actual laboratory and field conditions are far more complicated and cannot be accurately predicted using current technology.

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Vapor Fraction and Change in Vapor Fraction BTUfor MRF 1500 BTU Mix with 0.834% C6+ at 75 PSIA

Temperature [F]30 35 40 45 50 55 60 65 70 75 80 85 90 95 100

Vapor Fraction

0.95

0.96

0.97

0.98

0.99

1.00

1.01

Change in Vapor Fraction [BTU

/scf]

-125-120-115-110-105-100-95-90-85-80-75-70-65-60-55-50-45-40-35-30-25-20-15-10-505

Vapor/Feed RatioChange in Vapor Fraction BTU

Dew Point91OF

~ 97.1% vaporby mole

~ 71BTU/SCFloss due to

condensation

Figure 10. The change in vapor fraction and gas phase heating value associated with condensation of a 1,500 Btu/scf natural gas mixture (George and Kelner, 2006).

Flowing Gas Dynamics and Joule-Thomson Cooling

As the previous section shows, natural gas samples obtained through sample lines or captured in sample cylinders can undergo state changes (changes in temperature and pressure) that can lead to distortion of the gas sample composition. In the case of a sample cylinder exposed to temperatures below the hydrocarbon dew point, the condensed components will remain in the sample cylinder with the remaining gas phase, and the overall contents of the cylinder itself will remain unchanged as long as the cylinder valves are not opened. Research (Behring and Kelner, 1999) has shown that reheating the cylinder above its dew point for an adequate length of time will restore the gas sample to its original composition.

When the temperature of a sample stream drops below its dew point during the collection process, however – at some location within the sampling system, before it reaches the analyzer or sample container – the integrity of the sample is much more likely to be distorted beyond recovery. This is due to the fact that condensed components (water vapor or hydrocarbons) may collect at points within the sample line, regulator, or other system components and not make it to the analyzer or sample container. The remaining gaseous components will not be representative of the full composition of the original stream being sampled. In this section, two causes of temperature drops within the sample flow will be described.

As discussed by Behring and Kelner (1999), when natural gas flows through a restriction in the sample line such as a valve restriction, changes in the state of the gas can occur. If no heat is transferred to or from the gas, if the gas does no work (that is, the gas does not turn a compressor or turbine), and if the gas does not undergo a significant change in elevation, then the first law of thermodynamics states that the total energy of the gas will remain the same (Van Wylen et al., 1994). However, the flow obstruction may cause the energy within the gas to change from one form to another. In particular, the energy of the gas per unit mass will be redistributed between the static enthalpy per unit mass, h, and kinetic energy per unit mass, V2/2, as shown by the following simplified form of the first law:

oout

outin

in hV

hV

h enthalpy stagnation 22

22

(1)

10

The sum of static enthalpy and kinetic energy is known as the stagnation enthalpy, ho, so called because if the gas were to become stagnant and reach zero velocity, this equation would reduce to h = ho. Note that the enthalpy h is a thermodynamic property of the gas, and therefore is related to its temperature and pressure. As the gas stream accelerates through the flow restriction, its velocity will increase, and because total energy must remain constant, its static enthalpy h will decrease. The decrease in static enthalpy will, in general, cause the gas temperature and pressure to decrease.

Consider an example of gas flowing through a valve restriction, such as a short section of small-diameter sample tubing or a reduced-port valve (Figure 11). Under steady flow conditions, the gas must accelerate from state 1 into the restriction. At or near the throat of the restriction, state 2, the gas will attain its greatest kinetic energy, and by Equation (1), its static enthalpy will simultaneously drop. The gas will then decelerate back into the full-diameter tubing, and the static enthalpy will increase again.

Figure 11. Relative changes in static enthalpy and kinetic energy of gas flowing through a restriction with no heat transfer or work to or from the gas (Behring and Kelner, 1999). The red line shows how the relative potential for condensation of heavy hydrocarbons changes as static enthalpy changes.

If the kinetic energy at state 3 is the same as the kinetic energy of the gas at state 1, then the static enthalpy of the gas will return to its original value. The gas pressure, however, will be lower at state 3 than at state 1 due to frictional losses incurred in passing through the restriction, and a corresponding drop in temperature will occur between states 1 and 3. This process, in which gas flowing through a throttle undergoes a temperature and pressure reduction without performing heat transfer or work, is called the Joule-Thomson process (Van Wylen et al., 1994). The Joule-Thomson coefficient describes the amount of cooling of the gas per unit pressure drop; a standard value used for natural gas flows is 7°F per 100 psi of pressure drop.

Figure 12 shows a pressure-temperature path (1-2-3) that the gas might follow through the phase diagram in the case where little or no pressure recovery is attained downstream of the flow restriction. Note that the gas may cross the hydrocarbon dew point boundary as it travels in and out of the restriction, depending on the initial thermodynamic state, the amount of acceleration, and so on. This is the region in which condensation of heavy hydrocarbons can occur. If no heat is lost or gained by the gas inside the tubing, and it decelerates back to its original kinetic energy level, then the process will return to a line of constant enthalpy (between points 1 and 3) parallel to the lines shown in the figure. However, the potential for sample distortion still exists due to the acceleration of the gas and the temperature drop to state 2 at the restriction. The red line in Figure 11 shows how the potential for condensation and sample distortion increases within the valve and downstream.

Potential for condensation

11

Figure 12. An example of the changes in state of a gas passing through the flow restriction in Figure 11 (Behring and Kelner, 1999).

Use of the Phase Diagram as a Sampling Tool

Clearly, it is crucial that a natural gas sample stream be kept above its dew point during sampling to avoid condensation of components from the sample. Dew points can be measured directly in the field using a Bureau of Mines chilled mirror dew point tester (ASTM, 2000), but if the location is remote or measurements at many different sites are needed, use of the tester may not be practical. On the other hand, if reliable data on the gas composition – such as an analysis from an on-site gas chromatograph (GC) – is available before sampling equipment is installed, the dew point curve can be estimated using any of a number of commercial equation-of-state software packages, and the sampling equipment can be designed to maintain representative samples.

Figure 12 gives an example of how a phase diagram can serve as a tool to avoid sample distortion. Information on sample flow rates, temperatures and pressures at the entrance to a sampling system would be determined as part of the design process. Thermodynamic software would be used to determine changes in temperature and pressure of the gas as it passes through regulators, reduced-port valves, or sample lines exposed to atmospheric conditions. At critical locations within the sampling system, the temperature and pressure state of the sample would be plotted on the phase diagram to identify any locations where condensation and phase change might occur. The sampling equipment could then be designed to avoid these problems, using methods such as heating equipment to compensate for temperature drops or reducing pressure drops through regulators.

Any of a number of commercial equation-of-state packages can be used to predict the hydrocarbon dew point curve of an expected natural gas mixture. However, the prediction is only as good as the accuracy of the composition used as input. Small amounts of heavy hydrocarbons, n-hexane and heavier, can strongly affect the hydrocarbon dew point of a gas. Unfortunately, many field GCs cannot identify these heavier components separately, and only report a “lumped C6+ fraction” for the gas being analyzed. Work is ongoing to determine the best methods of “characterizing” the heavier components in this fraction when only the C6+ total is known.

Figure 13 shows several phase diagrams computed for a single gas composition assuming different characterizations for the hexanes and heavier hydrocarbons (George et al., 2005). The results were compared to experimental hydrocarbon dew point data for the same gas composition to determine the potential errors due to poor characterizations. The worst case was obtained by treating the lumped C6+ fraction as 100% normal hexane. Using this characterization gave computed dew points as much as 35°F below the experimental data. If this characterization had been used to design a sampling system, the samples could cool well below the hydrocarbon dew point, condensing out heavy components and distorting the sample. In general, research indicated that a natural gas composition must be known through nonane for its dew point to be computed

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accurately. This information can be obtained by analyzing the stream using a GC capable of detecting hexanes and heavier hydrocarbons separately. This may require a sample to be carefully obtained and sent offsite for analysis.

Figure 13. Effect of using various C6+ characterizations on predicted hydrocarbon dew point curves (George and Kelner, 2006).

Recent Research on Natural Gas Sampling Methods and Methods of Avoiding Sample Distortion

During preparation of the 6th edition of API MPMS Chapter 14.1, updates were made in several specific areas related to accurate natural gas sampling. These updates were based on results of research performed in support of the standard (Behring and Kelner, 1999; API, 2006), and on recent revisions to other relevant standards. Other research in the public domain has identified other techniques for minimizing sample distortion (Barajas and George, 2006; George and Kelner, 2006). This section will review sampling equipment designs and sampling methods that can reduce the potential for sample distortion through the mechanisms listed above.

Chemical adsorption can be avoided by using materials in sampling systems, such as stainless steel, that are chemically inert. Adsorption of hydrocarbon components onto seal materials can cause leakage and/or seal failure; Viton is a common material for o-rings and other seals, as it minimizes heavy hydrocarbon adsorption. API MPMS Chapter 14.1 recommends that sample cylinders used in sour and/or corrosive gas service should be specially lined or coated with epoxy, or undergo passivation. Very reactive components, such as hydrogen sulfide (H2S), should be analyzed on-site when practical, rather than taken by sample cylinder for offsite analysis.

Physical adsorption cannot be entirely eliminated from sampling systems, but as documented by Behring and Kelner (1999) and Barajas and George (2006), several steps can be taken to minimize sample distortion through adsorption and desorption.

Surface areas in contact with the sample stream should be minimized. Smooth surfaces will have less surface area where gas molecules can adsorb, and porous materials (such as plastics) should be avoided when building sampling systems.

Tests have shown that sampling systems respond more quickly to changes in moisture content when the sampling flow rate is increased, since this quickens the mechanism by which molecules adsorb and desorb from the sample tube walls and other “wetted” surfaces.

Thermodynamic conditions can also affect the physical adsorption equilibrium. Gas molecules have a higher tendency to physically adsorb at high pressures. Lowering the gas pressure in the sample system (through regulation) will tend to shift the equilibrium and desorb gas phase molecules, minimizing the resulting distortion.

Similarly, gas molecules have a higher tendency to physically adsorb at low temperatures. Raising the temperature above ambient temperatures (through active equipment heating) will also tend to shift the

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equilibrium and desorb gas phase molecules. However, this is most beneficial where other sampling conditions can slow down system response times.

Components dissolved into liquids: If liquids have the potential to enter a sampling system intended only for gas analysis, filters are suggested to prevent undesirable liquids from reaching the sample line, analyzers, regulators, or any other equipment with which the gas may come into contact. In the event that liquids do enter the sampling equipment, sample systems should be designed to be thoroughly and easily cleaned. Research (Behring and Kelner, 1999) has found wet steam to be the most effective cleaning agent for removing heavy hydrocarbon liquids from sampling equipment, provided the steam does not contain treatment chemicals or corrosion inhibitors that could also contaminate the equipment. Solvents that do not leave a residue after drying, such as acetone and liquid propane, are also generally effective. Silicon grease or other lubricants that may absorb components from the sample or elute contaminants into the sample should not be used on o-rings or seals.

While sample lines and hardware in sample systems are often permanently installed and may be hard to disassemble for cleaning, sample containers are easily transportable. Furthermore, their interior surfaces come into contact with gas samples for long periods of time. For these reasons, the API Chapter 14.1 standard requires that sample containers be purged and cleaned of liquid contaminants prior to each sample, using steam or another accepted cleaning method. Evacuating the cylinder to 1 millimeter of mercury absolute pressure or less will eliminate by vaporization any residual liquids not removed by the steam cleaning process.

Phase change due to Joule-Thomson cooling and flow dynamics can be avoided through the use of a phase diagram such as Figure 12 to select appropriate equipment. For instance, if a phase diagram of a sampling process indicates that Joule-Thomson cooling at a pressure regulator may cause sample distortion, heated regulators and/or heat trace are recommended to offset the cooling effect. Generally, care is recommended to provide sufficient heat to avoid condensation of gas components whenever any type of regulator is installed in a sample line or a pressure reduction occurs. This can be achieved using heated sample probes, heat trace along sample lines, catalytic heaters, and/or insulation.

As a safety margin against uncertainties in predicted hydrocarbon dew points, API Chapter 14.1 recommends that sampling equipment be maintained at least 30ºF (17ºC) above the predicted hydrocarbon dew point. This margin can be reduced where documented research shows that differences between calculated and measured hydrocarbon dew points for the gas stream of interest are less than 30ºF. This guideline should be applied to all equipment that contacts the gas sample, including sample lines, regulators, filters, valves, and sample containers.

One significant change in sampling equipment has been specified by the latest editions of API 14.1 and GPA 2166. This change involves the Fill and Empty sampling method, which is discussed in detail in both references. When samples are collected using this method, these standards require a drilled plug, a multi-turn needle valve, or another type of flow restriction to be placed at the end of a “pigtail” to control the sample flow rate (Figure 14). The purpose of the flow restriction and pigtail is to move the throttling process and associated Joule-Thomson cooling far from the sample cylinder, so that condensation in the sample cylinder is avoided (George et al., 2005). While earlier versions of GPA 2166 only allowed a drilled plug to be used as the flow restriction, other devices have been added to the method based on tests that successfully used needle valves instead of drilled plugs to shorten the time needed to obtain a sample.

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Figure 14. Sampling apparatus for the GPA Fill and Empty method (adapted from GPA, 2005).

Conclusion

This paper has reviewed several chemical and physical phenomena that can change the composition of a natural gas sample, thereby corrupting the sample and leading to inaccurate analysis of the gas properties. Such phenomena can include adsorption and desorption of heavy hydrocarbons, water vapor, and other components at the walls of sampling equipment; condensation of components due to Joule-Thomson cooling and phase change; and absorption of gas components into liquid contaminants. Research to understand these phenomena has led to techniques and standards for preventing them and avoiding their effects on sample accuracy. Perhaps the most useful tool in avoiding sample distortion is the phase diagram. Proper use of the phase diagram and thermodynamic analysis of the flowing stream can allow the designer to select regulators, heat trace, and other equipment that will avoid significant losses in hydrocarbon content and underestimates of water vapor content, which in turn can cause unnecessary production shut-ins or inequities in custody transfer. By explaining these phenomena to the reader, it is hoped that those who design and use sampling equipment can use the techniques to their benefit.

References

API, Manual of Petroleum Measurement Standards, Chapter 14 – Natural Gas Fluids Measurement, Section 1 – Collecting and Handling of Natural Gas Samples for Custody Transfer, Sixth Edition, American Petroleum Institute, Washington D.C., USA, February 2006.

ASTM D 1142, Standard Test Method for Water Vapor Content of Gaseous Fuels by Measurement of Dew-Point Temperature, American Society for Testing and Materials, West Conshohoken, Pennsylvania, 2000.

Bailar, J. C., Moeller, T., Kleinberg, J., Guss, C. O., Castellion, M. E., and Metz, C., Chemistry, Academic Press, New York, 1978.

Barajas, A. M., and George, D. L. (Southwest Research Institute), “Assessment of Sampling Systems for Monitoring Water Vapor in Natural Gas Streams,” Final Report to U.S. Minerals Management Service, Herndon, Virginia, USA, March 2006.

Behring II, K. A., and Kelner, E. (Southwest Research Institute), “Metering Research Facility Program, Natural Gas Sample Collection and Handling – Phase I,” GRI Topical Report GRI-99/0194, Gas Research Institute, Chicago, Illinois, USA, August 1999.

George, D. L., Barajas, A. M., Kelner, E., and Nored, M. (Southwest Research Institute), “Metering Research Facility Program: Natural Gas Sample Collection and Handling-Phase IV,” GRI Topical Report GRI-03/0049, Gas Technology Institute, Des Plaines, Illinois, January 2005.

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George, D. L., and Kelner, E., “Additions and Changes to the Latest Revision of API Chapter 14.1,” in Proceedings of the Eighty-First International School of Hydrocarbon Measurement, Oklahoma City, Oklahoma, May 2006, Class #5255.

GPA Standard 2166-05, Obtaining Natural Gas Samples for Analysis by Gas Chromatography, Gas Processors Association, Tulsa, OK, USA, October 2005.

Gregg, S. J., The Surface Chemistry of Solids, Reinhold Publishing Corporation, New York, 1961.

Mayeuax, D. P., private communication, 2006.

Van Wylen, G. J., Sonntag, R. E., and Borgnakke, C., Fundamentals of Classical Thermodynamics, Fourth Edition, John Wiley & Sons, New York, NY, USA, 1994.

Weast, R. C., Astle, M. J., and Beyer, W. H., editors, CRC Handbook of Chemistry and Physics, 66th Edition, CRC Press, Boca Raton, FL, USA, 1985.

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THE STANDARDS PERTAINING TO SAMPLING AND CONDITIONING OF NATURAL GAS

Fred Van Orsdol, SPL, Inc.

In the mid 1980s, the industry was deeply involved with the United States Bureau of Land Management (BLM), dealing with allocation measurement. The government was seriously considering eliminating allocation measurement wherever there was federal jurisdiction. During this process, the American Petroleum Institute (API) and the Gas Processors Association (GPA) member companies had worked extensively with the government to educate them on allocation practices and contractual obligations to provide “fair and equitable” measurement for all parties with a direct financial interest, while significantly reducing the costs associated with measurement. The industry was able to demonstrate to the BLM that without allocation measurement, tens of thousands of producing locations would be unprofitable and would have to be abandoned. Chevron, Mobil, Phillips Petroleum, and other major companies were instrumental in this process. The state of New Mexico was a staunch supporter of the industry position as well. They recognized that the companies would have to abandon leases and that the impact on the state (as well as interest owners, the companies, and the federal government) would be huge.

As a sidebar to the work on allocation measurement, which is based on the relaxed but “fair and equitable” application of custody transfer systems and procedures, the industry assisted the BLM to become very familiar with custody transfer standards in place at the time.

During a discussion between Ray Thompson (project lead with the BLM) and me (as the designated spokesperson for the industry as we dealt with the BLM on allocation measurement), Mr. Thompson noted that there were gaps in our standards and asked me simply, “Will you close those gaps or does the BLM need to close them for you?” He went on to specify that the GPA had a standard for spot sampling, but no one had a standard for composite or continuous sampling, no one had a standard for flow computers, and no one had a standard for allocation measurement. On behalf of the industry and after previously consulting with both the GPA and the API and their member companies, I immediately committed to Mr. Thompson that we (the industry) would close the gaps, and invited participation by the United States Minerals Management Service (MMS), the BLM and any other parties with a direct interest.

As Vice Chairman, then Chairman, of the API Committee of Gas Fluids Measurement (COGFM) and as Chairman of GPA Technical Section H, I was able to lead and/or be involved in keeping the promise to the BLM. The full process required over a decade. The Natural Gas Sampling Research Project, originally sponsored by the API with technical support from the GPA, was a very needed and useful enterprise for developing API Manual of Petroleum Measurement Standards (MPMS), Chapter 14.1 into the document it is today; covering spot, composite, and continuous sampling systems and procedures. The research, which extended over several years, ensured that the recommendations contained in it were well researched and based on technically defensible data. Many organizations and individuals contributed a great deal of time, effort, money, and resources to the project – including the MMS.

I think continuing this approach is critical as we move forward with standards development. Also, insist on seeing the data developed in accordance with API recommendations when a vendor claims they have an API compliant system or procedure. Run backwards from vendors claiming to have “API Approved” systems or procedures. The API does not issue approvals on measurement equipment. The API does provide test protocols for some equipment and procedures, so that an independent flow lab can determine whether or not a new system or procedure will perform as well as those included in the custody transfer standards and has a database sufficient to document custody transfer level performance.

The GPA, API, the International Standards Organization (ISO), and many other organizations have natural gas sampling standards, but none have the database behind them like API MPMS, Chapter 14.1 and the GPA interpretation of that data in their Standard 2166. The only significant issues between the API and GPA standards revolve around the GPA Separator and Constant-Pressure Cylinders (Piston Cylinders). Simply put, the API doesn’t recommend the use of GPA Separators. The GPA recommends using the GPA Separator whenever liquids are expected in the meter run. In my opinion, they should never be used. They carry over contamination from one location to the next (unless they are cleaned before each use, which is expensive and time-consuming). They create liquids (condensation) when they are used under cold ambient conditions, where the hydrocarbon dew point (HCDP) of the gas stream is above the ambient temperature, unless adequate heating is provided, which is difficult and expensive. Finally, the custody transfer quality samples collected during the research project to evaluate various methods clearly showed that the GPA Separator is more likely to produce problems than not,

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and it is not required to collect representative samples. It is simply too small to act as a separator anyway – the residence time is not sufficient.

The GPA seems to prefer piston cylinders over single-cavity cylinders, while the API tends to favor single-cavity cylinders since they are easier to clean. Constant-pressure cylinders should only be used for custody transfer applications if they are disassembled and cleaned prior to each use, particularly if there are heavy components or heavy contaminants in the gas stream that will produce carry-over contamination from sample to sample.

The standards have many common recommendations. For example:

1. Sample probes should always be used and should project well inside the pipe.

2. Sample probes must be designed to withstand the flowing velocity of the stream without failing. In systems with high flowing velocities, such as in ultrasonic metering systems, the probes must be very robust and designed in accordance with recommendations in the standards (based on maximum allowed Strouhal numbers).

3. Fill-and-empty spot sampling requires the use of an extension tube or “pigtail” to ensure that the Joule-Thomson cooling effect does not produce chilling and condensation in the sample cylinder.

4. Heat tracing and insulation on composite and continuous sampling systems must be provided whenever ambient or operating conditions are able to cool the stream to a temperature below the HCDP.

5. Flow-proportional composite samples are generally more representative than time-proportional samples, particularly if a flow switch is not provided to stop sampling altogether when a time proportional system is sampling from a system where flow has stopped.

Note that the API standard is far more comprehensive than other gas sampling standards, in that it contains sections addressing in detail such topics as:

• Stratification in still containers,

• Composition recovery when a properly collected and representative sample is collected, then cooled sufficiently to produce condensation, then reheated to re-vaporize all the sample,

• Preparation of gravimetrically-prepared gas calibration standards,

• A detailed lab review inspection checklist, including recommendations for the maximum acceptable limits on repeatability and reproducibility for gas chromatograph (GC) performance,

• Recommendations relative to measuring or predicting HCDPs.

ISO 10715 is similar to and based partially on portions of GPA 2166 and API MPMS, Chapter 14.1 in most regards, but is not as comprehensive or as well supported by independent research data. It does address very low pressure sampling in glass containers, primarily for contaminant determination, which is not specifically covered by the API or GPA standards. I would note that glass is a relatively porous material, relative to stainless steel or phenolic/epoxy-lined stainless steel cylinders that would be used for this type of sampling under API guidelines, and glass is not recommended by the API for sampling reactive materials or materials likely to be adsorbed.

The ISO allows PVC (poly vinyl chloride) to be used in low pressure applications also, but it is not recommended by the API.

For the fill-and-empty method, the GPA Separator is recommended by the ISO. Other spot sampling methods (e.g., evacuated cylinder, helium pop, continuous purge, etc.) are recommended without qualification (ignoring their potential for creating condensation during the sampling process in some instances). API MPMS, Chapter 14.1 makes it very clear, for example, that the continuous purge method is not recommended for gas near or at its hydrocarbon dew point temperature.

Scopes of Application (condensed - see the standards for the full scopes):

API MPMS, Chapter 14.1:

From the Introduction Section – This standard incorporates guidelines and recommendations for obtaining representative samples safely. It should be useful as a resource document for training programs as well. This standard attempts to consider both sweet and sour gas streams as well as high- and low-pressure

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applications. Streams at or above the hydrocarbon dew point temperature and streams that may contain water vapor up to the point of saturation are addressed.

From the Purpose and Scope Section - The purpose of this standard is to provide a comprehensive guideline for properly collecting, conditioning, and handling representative samples of natural gas that are at or above their hydrocarbon dew point.

The standard considers spot, composite, continuous, and mobile sampling systems. This standard does not include sampling of liquid streams.

This standard includes comments identifying special areas of concern or importance for each sampling method included. It is intended for custody transfer measurement systems and may be applicable to allocation measurement systems.

The accuracy of moisture determinations from samples collected using the recommendations in this standard has not been determined.

This standard does not include sampling multi-phase flow (free liquid and gas) or supercritical fluids.

GPA 2166:

The purpose of this publication is to recommend procedures for obtaining samples from flowing natural gas streams that represent the composition of the vapor phase portion of the system being analyzed. These representative samples are subsequently transported to a laboratory and analyzed for composition and/or trace contaminants or analyzed onsite by portable or on-line chromatographs.

Methods outlined in this publication are designed for sampling natural gas from systems that are at or above the hydrocarbon dew point temperature. As the temperature of the flowing stream decreases or the pressure increases to impinge upon the hydrocarbon dew point, it becomes increasingly difficult to obtain a representative sample of the flowing stream. This standard does not address accounting for the liquid hydrocarbon portion of two-phase systems.

ISO:

The purpose of this document is to provide concise guidelines for the collection, conditioning, and handling of representative samples of processed natural gas streams. It also contains guidelines for sampling strategy, sample probe location, and the handling and design of sampling equipment. It considers spot, composite (incremental), and continuous sampling systems. This document does not include sampling of liquid streams or streams with multiphase flow. Traces of liquid, such as glycol and compressor oil, if present, are assumed to be intrusive and not a part of the gas to be sampled. Their removal is desirable to protect the sampling and analytical equipment from contamination. This document can be used for custody transfer measurement systems and allocation measurement systems.

Natural Gas Sampling Research Project Overview:

• Laboratory Phase - conducted at Southwest Research Institute (SwRI) (Static and Dynamic Test Series) - simulated winter and summer ambient conditions.

• Simulated Field Dynamic Testing - conducted at Colorado Engineering Experiment Station, Incorporated (CEESI) under winter and summer conditions.

• Operating Location Tests - conducted in southern Louisiana, Colorado, and Wyoming.

• Fluid-dynamic Simulation Studies by SwRI and Texas A&M University.

• Laboratory screening for project-associated labs led to the Lab Review Procedure/Inspection Checklist that appears in the final standard as an appendix.

• Attempt to identify spot sampling methods that perform best when the flowing stream is at or near its hydrocarbon dew point.

• Evaluate measures required to make composite sampling systems collect representative samples under extreme ambient conditions (i.e., temperatures far below the dew point of the flowing gas stream).

Areas Investigated:

• Sample probes (necessity, location, and orientation)

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• Sample lines (materials, length, cleanliness, etc.)

• Sample cylinders (materials, cleaning, handling, design, etc.)

• Spot sampling methods

• Sample system valves

• Composite sampling systems and procedures

• Continuous/on-line sampling systems

• Gas chromatograph inlet and injection systems

• Lab review procedures

• GPA separators

• Regulator heat input requirements

• Heating samples after condensation has occurred

• Stratification in stagnant sample cylinders

• Heat tracing and insulation requirements

• GC inlet filters, dryers, and membrane separators

• Cleaning requirements for constant-pressure cylinders

• Comparisons of various composite sampling systems

• Vacuum sampling methods

• Dew point predictions and measurement

• Extending the actual scope of API MPMS, Chapter 14.1 to include streams at or near the hydrocarbon dew point

Ranges of Conditions and Properties:

• Heating values from 800 to 1,750 BTU/scf

• Pressures from 10 psia to >1,000 psig

• Temperatures from 12°F to >110°F

Key Findings:

• Effectively considering the dew point is everything!

• A representative sample allowed to cool and condense in a non-reactive sealed container will yield the original analysis - if appropriately heated prior to withdrawing any sample.

• Calibration standards do not stratify due to gravity as long as they remain above their dew point temperature.

• GPA Separators are generally not recommended.

• Sample probes extending well beyond the pipeline wall are critical to collecting representative samples.

• Calculation procedure provided in the latest revision of the standard to help design probe systems.

• Sample probes need to be located at least five pipe diameters (a.k.a., 5D) from flow disturbances (e.g., valves, orifices, thermowells, etc.).

• Clean sample cylinders are a must.

• Clean sample system tubing is a must.

• New, unclean tubing causes bias in GC results (due to machine oil contamination).

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• Closed-end or slow-purge spot sampling methods are best for rich gases (e.g., fill-and-empty with a pigtail installed, displacement, helium pop, etc.).

• Continuous purge only works well with dry, lean gas.

• GPA Separators have rarely been used in full accordance with the GPA procedures.

• Continuous sampling systems must incorporate adequate heat tracing and insulation in order for the gas to remain above its dew point temperature, especially during upset conditions.

• Stainless steel and nylon proved to be the best tubing materials.

• Note: The working group developed a comprehensive lab review inspection checklist that may be used as a guide to evaluate laboratory performance.

• Pressure regulators on the inlets of continuous sampling systems require a lot of heat to ensure the point of regulation is maintained above the hydrocarbon dew point temperature.

• Even residue gas sample lines need to be heat traced and insulated sufficiently to remain above the hydrocarbon dew point at all times, since condensation during upset conditions at the plant delivering the residue gas may take days to return to representative conditions (i.e., no condensation in the system that would create a bias due to selective adsorption and desorption).

• Steam cleaning is the most “robust” sample cylinder cleaning method.

• The less material between spot sample cylinders and the sample probe, the better.

• The fill-and-empty, helium pop, and displacement methods of spot sampling appear to be the methods best capable of collecting representative spot samples when the ambient temperature is well below the dew point temperature of the gas being sampled.

• Membrane separators were tested and did not affect analytical results when properly utilized.

• Filters and dryers in well-designed sample loops did not degrade analytical results.

• Lubricants and contaminants are very difficult to remove from constant-pressure/piston sample cylinders (must disassemble and clean metal parts and replace o-ring seals).

• Dryers did not affect analytical results in well-designed systems.

• “Pigtails” are essential to achieve good results with the fill-and-empty spot sampling method.

• Tygon®, Teflon®, and polyethylene tubing produced biased gas sample analyses.

Key Points to Check:

• Place sample probe tip into the center third of the pipe (or for large diameter lines, the probe should extend well into the flowing stream – see the standard for detailed guidelines).

• Keep sample lines as short as practical.

• Stainless steel cylinders and fittings (SS or nylon tubing) for routine sampling.

• Consider whether sample line could/should be heated.

• Keep sample cylinder properly cleaned.

• Spot sampling with closed-end methods or fill-and-empty.

• Composite sampling with flow-proportional control.

• Do not use GPA Separators or sample hoses.

• Use 36-inch or longer pigtail for fill-and-empty method.

Examples of common sampling system deficiencies observed during field audits include:

Issue 1: No sample probe.

Issue 2: BTU content over 1,035 BTU/scf, but no heat tracing or insulation with composite or continuous sampling systems.

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Issue 3: Sample point in poor location.

Issue 4: Sample system tubing too long and/or too complex.

Issue 5: Time-proportional composite sampling system (rather than flow-proportional).

Issue 6: Spot sampling for custody transfer measurement (cannot be representative except in absolutely stable systems).

Issue 7: Incorrect number of fill-and-empty cycles with fill-and-empty method.

Issue 8: No pigtail used with fill-and-empty method.

Conclusions:

We have made great strides in understanding the requirements for successful natural gas sampling, but additional research and education is needed in some areas. Following are a few examples.

• The Pitot and bypass (slipstream) method of spot sampling needs to be fully evaluated to demonstrate if it can produce representative samples without the requirement for discharging volumes of gas to the atmosphere (as compared to the fill-and-empty method).

• Test data needs to be collected to support the effectiveness of API MPMS, Chapter 14.1 recommendations relative to accurately determining moisture content.

• Research is needed to determine systems and procedures necessary to sample multiphase streams successfully.

• Finally, we need to develop methods for accurately predicting the hydrocarbon dew point of a stream.

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SPOT AND COMPOSITE SAMPLING FOR BTU ANALYSIS

DETERMINATION AND NATURAL GAS PHYSICAL PROPERTIES

David J. Fish, Welker, Inc.

Purpose

The need to be able to take a representative sample of a hydrocarbon product is necessary to ensure proper accounting for transactions and efficient product processing. The various sampling methods that are available and the options and limitations of these methods are investigated; the most appropriate equipment to use; the reasons for its use and correct installation of the equipment are also addressed.

Introduction

The amount of hydrocarbon product that is transported between producer, processor, distributor and user is significant. To be able to verify the exact composition of the product is important from an economic and product treatment standpoint. A small percentage savings made by correctly determining composition will quickly recoup the investment made in the purchase of a system designed to obtain an optimum sample. In addition, if the best sampling procedures are followed, the potential for disputes between supplier and customer will be greatly reduced. The importance of properly determining hydrocarbon gas composition benefits all parties involved and will achieve greater significance as this resource becomes more expensive and plays a larger role in our energy needs worldwide.

From the Gas Processors Association publication GPA 2166-05, "The objective of the listed sampling procedures is to obtain a representative sample of the gas phase portion of the flowing stream under investigation. Any subsequent analysis of the sample regardless of the test, is inaccurate unless a representative sample is obtained.” And, from ISO-10715, a representative sample is, “A sample having the same composition as the material sampled, when the latter is considered as a homogeneous whole.” API 14.1 offers a similar statement in the latest revision, “a representative sample is compositionally identical or as near to identical as possible, to the sample source stream”, as does ASTM 5287-08. These standards are the most common referenced on Gas Sampling procedures, along with the AGA Gas Measurement Manual, Part No. 11, Section 11.3.

Proper sampling is fundamental to the correct determination of the product composition. In a majority of cases, the sample is also the source for the determination of the specific gravity of the gas. This figure is a critical component of the flow formula, from which we derive the product quantity. An error in sampling effects both quality and quantity, and ultimately, profitability. Most current Gas Chromatographs boast an accuracy level of ½ of a BTU, but that should not be the comfort zone for the measurement department. A faulty sampling method or improperly installed and maintained equipment may alter the BTU content of the flowing stream by 25+ BTU. While the accuracy of the GC may be considered as a given, the properly executed technique for taking the sample is certainly not a given.

Gas Sampling

Natural Gas sampling has been performed for years with techniques handed down from generation to generation. Most of the methods are not sufficient to meet today's requirements of accuracy and repeatability; however, standards have been developed to reach toward these demands. The most widely known standards are GPA-2166-05 and ISO-10715. API has produced a revised API 14.1, which was published in June, 2001. It has been updated and revised in 2006. This new standard has already generated significant interest in proper sampling techniques, due to a large volume of data produced during the revision work.

Proper maintenance of all sampling equipment is vital to the operations of all sampling methods. A review of relative sampling standards and the manufacturer’s operation, installation and maintenance manuals, is an important step in the total accurate sampling process. Dirty or poorly maintained sampling apparatus will adversely affect the final results and profitability of the gas company’s operation.

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Sampling Components

Sampling can be accomplished by primarily three techniques; spot, continuous composite or continuous on-line sampling systems. The various components of a sampling system deserve individual consideration, before the various sampling procedures are investigated. All components should be compatible with the fluid being sampled.

Regulators - On-line analysis should use regulators to reduce the pressure to the analyzer. They will reduce the gas volume to the sampler, thus minimizing the time delay between the sample point, via the regulator, to the analyzer. This will lessen any negative effect on the gas sample by ambient conditions.

Insertion type or probe regulators are preferable as they will be able to reduce the sample pressure in the flowing stream enabling a minimization of the Joule-Thompson effect created by the pressure drop. The ambient temperature of the pipeline gas is transmitted via thermal fins, to offset the cooling effect. The design purpose of the probe regulator is to not create liquids where liquids do not exist. They were designed for rich, dry gas systems. All aspects of the regulator systems should consider Hydrocarbon Dew Point impact on the process and be temperature conditioned to prevent those issues as much as possible. Not all installations will require attention, but the ones which don’t now days, will be few and far between. Wet gas systems present a new sampling challenge.

Valves - If shut-off/isolation valves present a restriction that causes a pressure drop, it is possible that condensation could occur. Large orifice valves should be used, as restrictive valve paths can cause fractionization of the sampled gas. API 14.1 addresses these porting issues for valves used in the sampling process.

When used with a collection cylinder it is important that there are no leaks from the gland. Light ends will be the first to leak off, thereby causing the sample to be overrepresented with heavy ends. It is wise to use valves with soft seals to give a positive shut-off.

Filters - For on-line analyzers, it is sensible to install a filter. Proper selection of the filter flow capacity and the particle size capacity should be encouraged. A filter that is too small or does not have a sufficient drip pot capacity for gases that have entrained water, is a recipe for high maintenance and off spec analysis. It is prudent to invest in a reasonable filter.

Relief valves - Regulators should have a relief valve installed downstream, if the equipment downstream is not able to withstand full upstream pressure. Regulators will not always give a guaranteed shut-off and their lock-up pressure will climb to a dangerous level should there be failure to attain a good shut-off such as seal damage, diaphragm damage or impurity build-up on working parts and sensing lines.

Pipework - Should be as short and as small a diameter as possible. This will assist in minimizing the time delay from sample point to the analyzer or cylinder. It will also help maintain the sample integrity. When used with on-line analyzers, sample delivery lines should slope upward from the probe to the analyzer to prevent condensation and impurities entering the analyzer. Lead lines to continuous samplers should slope back and drain towards the pipeline.

Heating Elements – There is sufficient evidence to show that heating all components of a sampling system is a prudent step in having a reliable and accurate sampling system. The hydrocarbon dew point of a natural gas stream is a critical issue in obtaining a representative gas sample. API 14.1 spends considerable time on this issue of heating and Hydrocarbon Dew Point, as does GPA 2166-05.

Probes - The correct placement is at the top of the pipe, into the center one third or at least 200 mm (8 inches) for larger diameter pipes; in an area of minimum turbulence, that is, away from headers, bends, valves, etc. Turbulence will stir up the contaminates that usually reside at the bottom of the pipeline and are therefore not normally part of the gas stream. By having the probe at a point of turbulence these contaminates will be taken into the sample, giving a sample that is not representative. The key is to have the probe in the center of the line in the correct spot (positive velocity/no turbulence) with a proper valve on the outlet. Field applications have shown that mounting the probe on the top of the pipeline is the preferred location. Side, lower or bottom mounts can easily encourage free liquids (if present) to migrate into the sample system.

Sample Pump - These pumps are, of course, needed to extract the sample from the line and transfer the sample to the analyzer or collection cylinder. They should have the capability to be able to extract the sample under flowing conditions, maintain a consistent discrete size of sample, take a fresh purged sample every time and have the ability to be controlled by a timer or proportional-to-flow controller. This forms the heart of the continuous gas sampling system. If the pump or sampler is unable to perform all these functions, a representative sample will not be taken and the sampling exercise will be flawed.

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Pumps can be either pneumatic or electric. The safety requirements of the electrical components such as motors and solenoid valves and the environmental protection rating, dictate careful selection and compliance with applicable codes. The selection options may well be limited if electrical components have requirements which are incompatible with the use of standard components elsewhere in the system.

Sample Cylinders - Used for the collection of gases and light liquid hydrocarbons, sometimes called "sample bombs". The cylinders come in three forms; one is a plain single cavity cylinder with a valve at each end, one is a single cavity, single fill cylinder with a removable inner bladder and valves at each end, and the third is a Constant Pressure Sample Cylinder, which takes the form of a closed end cylinder with an internal piston. Before using this cylinder, one side is pressurized forcing the piston to the sample end. When the sample is taken, the product is then collected against that back pressure and stored at whatever pressure is pre-charged at the back of the piston. Using the Constant Pressure Cylinder the sample can be collected at a pressure above the vapor pressure of the light ends. By having the piston at the end of the cylinder, the need for excessive purging is eliminated. Pulling a vacuum in the sample cylinder (which is often destroyed by technicians) or using the water outage method is not necessary. It can be guaranteed that the sample taken is composed entirely of the gas being sampled. The hook-up is simple and straightforward making the operation easier for technicians and minimizing the possibility of an incorrect sample being taken. The bladder cylinder also allows for starting with a voided chamber, as the bag is collapsed by a minimal back pressure prior to starting.

Sample cylinders should be constructed with a material that is compatible with the gas. For instance, H2S can be absorbed into the structure of 316 Stainless Steel. This will necessitate coating the inside of the cylinder. The resultant sample will not be truly representative otherwise.

Sample cylinders are normally protected with bursting discs. They are less expensive and are lighter weight than relief valves, though their proper selection and replacement should have more importance than is sometimes given them.

With all of the notes on the various components should go the comment which is one of the basic rules of sampling. The materials of construction of the sampling equipment that come into contact with the sample are to be compatible with the product being sampled. It is normally reasonably safe to use 316 stainless steel and Viton elastomeric components. Kalrez®, PTFE, Duplex Stainless Steel, Inconel, Titanium and other materials are becoming common. One should look for these materials in selecting equipment, and ask questions of suppliers about material selections.

An additional major factor in correct sampling procedures is an awareness of the Hydrocarbon Dew Point of the gas stream being sampled. The importance of knowing the HCDP is related to 1). The ambient temperature; 2). The temperature of the equipment being used to collect the sample; and 3). The temperature of the flowing stream. The creation of liquids due to equipment design and equipment temperature must be avoided. Determination of the HCDP of the gas stream can be done by the chilled mirror method or by the use of a number of equation of state models for hydrocarbon dew point determination. There are several programs available such as Peng-Robinson or SRK. The variations of the calculated results between different equations of state are so wide, that it is strongly recommended to add 20 to 50F (11 to 28C) to the answers. This is to assure the operator that he is designing his sampling system temperature requirements above the actual hydrocarbon dew point.

Spot Sampling

While there are several methods for spot sampling natural gas, three common methods in use today are the fill and purge method detailed in GPA-2166-05 section 9.1, the piston cylinder method detailed in section 9.7, and the Helium Pop method detailed in section 9.5.

Spot sampling was the primary method of acquiring a sample for analysis until the early 1970’s. This method is still widely used today. In today's world of growing trends toward therm-measurement and therm-billing, this method is increasingly expensive in analytical cost and man-hours, as well as a very questionable method of assessing an accurate heating value to volume sales. It is at best a "spot" sample of what was present at the moment the sample was taken. Minutes before and minutes after become unknown guesses. While this may be a reasonable risk if the gas source is known by a long historical data base, most gas being consumed today is a combined gas from several origins, or is switched from source to source by contractual updates; in some cases by daily or even hourly arrangements. This author has been on location and witnessed a 62 BTU increase at a single sample point, within a one-hour time frame. It was mainly attributed to both a substantial increase and

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decrease in flow rate as well as well selection changes within the gathering grid. Also, we find typically, that the older the well and the longer it stays in production, the higher the BTU value will become. Natural gas is an extremely fragile product and at almost every step in the production, transportation and distribution of natural gas, will be exposed to a potential adverse effects on its quality. Switching wells, pressure changes, temperature changes and storage vessels are only a few of the items that can add or subtract BTU values on the gas moving through measurement stations. Thus, a spot sample may not even represent the correct source in question.

In early years, the spot sampling method was used where by the gas was introduced into the cylinder until it reached line pressure, and then was transported to the laboratory for calorimeter or chromatograph analysis. As the known quality of the gas (BTU value) became more important, tests were conducted to determine if the gas was being altered by the procedure used to fill cylinders. It was determined that contaminates such as air were being introduced to the collected sample and a new filling method was needed. The fill and purge method was adopted and after sometime it was determined that the introduction of liquids was occurring by this process and thus a newer method was created. This newer method is known as the GPA method using a manifold for filling the Standard Cylinder. This GPA method reduced the negative effects of the "filling only" procedure. The manifold allows gas to be "trapped" in the cylinder at full pressure, rather than simply "dead ended" into the cylinder, i.e. zero pressure up to line pressure.

As the quality of gas became a critical part of billing, along with volume (std. cu. m. or std cu. ft.), the industry again reviewed the Standard Cylinder and its accuracy.

The need for maintaining the gas at full line pressure from beginning to end became evident. Any reduction in pressure and change in temperature from the line condition at the time of sample was deemed to alter the gas analysis in almost every case. Only low BTU gas (975 BTU and below) seemed to possibly escape alteration.

It became evident that when the Standard Cylinder was being filled, the heavy ends dropped out as condensate in the cylinder until higher pressures were reached in the filling process. The GPA method helped eliminate this problem. But when the cylinder was being bled into the chromatograph, there was no way to keep the pressure elevated in that cylinder. As the cylinder was opened, the light ends escaped first, thus giving a certain BTU value. As the analysis continued, the BTU value increased due to the heavy ends remaining in the cylinder, thus altering the BTU value in a higher direction. As it is normal that more than one test is performed, due to concerns of accuracy or custody transfer, repeatability was more often than not, impossible. It became clear that the decrease in pressure was altering the gas composition.

It was in this environment that the Constant Pressure or Sliding Piston Cylinder was designed and created. With an internal piston with seals, it was possible to pressurize (pre-charge) the cylinder with an inert gas supply (or the pipeline gas itself), and then turn the cylinder around and fill it slowly from the opposite end. By letting the gas push against the piston while "slowly" venting the pre-charge gas, the sample was taken at full line pressure from start to finish. Then, in the laboratory, a gas supply could be connected to the pre-charge side equal to the pipeline pressure. As the sampled gas is injected into the chromatograph, the piston is being pushed by the pre-charge gas. While the cylinder is being emptied, full pressure is being maintained and the gas composition is not being altered as a result of pressure reduction. The cylinder can be stored, or sent to another laboratory for confirmation, and when the remaining gas is analyzed, it will give repeatable results, because the condition of the gas is maintained by the constant pressure cylinder.

The cylinder is equipped with valves, safety reliefs and gauges on both ends, and thus the pressure can be controlled and monitored at all times on both ends. The temperature is maintained just as with Standard Cylinders i.e. heating blankets, ovens, or water baths.

This procedure has proven to give extreme accuracy in both spot sampling procedures as well as in automatic sampling systems. The Constant Pressure Cylinder has been tested against the laboratory chromatograph and on-line chromatographs, and has shown to maintain the integrity of the sample to within a very close value of the pipeline gas. No other method consistently performs at this level. Also, the richer the gas, the more alteration occurs with older methods. Because of this high level of preserving the sample, the cylinders are now used as calibration standard cylinders. That demand of maintaining accuracy is critical and gives the piston cylinder a solid recommendation for integrity.

The Constant Pressure Cylinder also brings with it, additional safety in handling the sample. No longer do you have to purge the cylinder and vent large amounts of gas to the atmosphere. A brief purge of the sample line up to the cylinder is all that is required. The piston is at the sample end of the cylinder when you commence to fill, so there is no "dead volume" to purge.

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Also, because of the design of the cylinder, with seals on the end of caps, it cannot be over pressured to the point of exploding. If the cylinder is over pressured, the safety reliefs will allow the pressure to escape. In the rare event that they fail to work the cylinder will swell and the seals will stop sealing, allowing the product to escape safely.

Constant Pressure Cylinders have served the industry for 25 years to provide accurate sampling procedures, better sampling systems, repeatability, safer handling, accurate analysis and storage of samples as well as storage of gas and liquid standards for the laboratory. All updated ISO, GPA, ASTM and API standards and committee reports, address the proper usage of Standard and Constant Pressure Cylinders for the gas and liquids industry.

A third cylinder design available today, is a single cavity cylinder with an internal, replaceable bladder or liner. Relatively new to the industry, it is being used in several research programs as a third method and to establish data on its performance and results. The bag starts at zero pressure and zero volume (a slight back pressure is introduced to collapse the bag completely), thus eliminating the need to purge the cylinder cavity. After each use, the internal bag is removed and discarded, eliminating the need to clean the cylinder.

Because of the increasing cost of one BTU, more and more companies are improving their methods, and departing from older spot sampling practices.

Composite Sampling

Composite sampling is the proven middle ground between spot sampling and the continuous on-line analytical gas chromatographs.

Composite or Grab sampling is the collection of the gas by direct introduction into a sample cylinder from a probe/valve combination or by means of a timed or proportional-to-flow sampler.

A composite gas sampler or gas sampling system consists of a probe, a sample collection pump, an instrumentation supply system, a timing system and a collection cylinder for sample transportation. Its sole objective is to collect and store a representative composite sample at line conditions, allowing it to be transported to the laboratory for repeatable analysis.

This package will mount on a pipeline and collect samples over a desired sample period unattended. For the sake of illustration, a description of a common system is provided here.

An engineered probe should be installed which extends into the middle 1/3 of the flowing stream. There is relief in API 14.1 for large diameter piping, but the accepted norm is the center 1/3 of the pipeline. This location should be chosen to provide a representative sample of the gas stream, thus devoid of stagnant gas, i.e. blow down stack, and devoid of free liquids and aerosols, i.e. downstream of piping elbows or orifice fittings which cause turbulent flow. The probe should have a large ported outlet valve to prevent fractionation, resulting in compositional changes in the gas.

A self-purging sample collection pump designed to operate under line conditions should be located above and as close to the probe as is practical and possible. Filters, drip pots, screens, regulators and such conditioning equipment shall not be placed between the probe and the sampler, as this will affect the representative nature of the sample which is taken. Inlet check valves can also cause the gas to fractionate, due to the restriction it causes in the line.

The sampler instrumentation source can be from the pipeline itself (the most common installation) or from an auxiliary instrument supply.

The timing system can be a simple function timer and solenoid, a proportional-to-flow signal conditioner and solenoid, or simply, a solenoid ready to be connected to field RTU's or other electronic devices capable of providing the desired signal.

The sample collection cylinder can be either a conventional single cavity sample cylinder, the lined cylinder or piston style, constant pressure sample cylinder. As these cylinders will be transported, they should meet design criteria such as ASME Section 8 or carry approvals from recognized agencies such as D.O.T., DNV, Lloyds, etc. A typical system would include a 500ml cylinder which would be used on a monthly basis to contain 2200+ bites of .2 cc size during the sample period.

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Using the grab sampler, it is possible to obtain a representative sample over a pre-determined period. It is the only practical method for collecting a continuous sample. The grab sampler will introduce a set volume, taken in equal amounts to the collection cylinder over a set period and is the preferred method when a representative sample has to be taken over time.

It has the advantage of being able to measure precisely a predictable amount over a given period when using a timer, and can also take samples proportional-to-flow when taking a modified signal from a flow meter.

In addition, the sample is taken from the flowing stream at the system pressure and can be fed into the sampler or sample cylinder at the flowing pressure; thus any change in composition is avoided.

Another feature required of any sampler is that it should not have areas or pockets where residue of previous samples can accumulate and, must take a fresh grab or bite of gas each time it samples.

This then describes a typical continuous composite sampling system, which has been proven to provide a representative sample for analysis. Such systems have been tested against continuous on-line gas calorimeters and gas chromatographs with + 1 BTU accuracy for the total sample period, at considerably less cost and maintenance than on-line GC's.

On-line Analyzers

And finally, in the realm of gas sampling there are the continuous on-line analytical units, the calorimeter and the chromatograph. These units have their place in the past, the present and will continue to have an important place in the future of gas sampling. It is their cost, power requirements and typical up-keep that precludes their use in 1000's of locations. On-line analysis is convenient, although it is dependent on the accuracy of the analyzer, its correct calibration and the quality of the sample reaching it. It tends to be expensive to install and maintain. Economics, remote location, and downtime for service dictate the use of spot or composite sampling techniques at a majority of sample points and installations. It is also important to point out that with on-line units there is no second or third chance at analysis, and no second opinion option, as is the case with a sample in a sample cylinder.

On the immediate horizon, a new technology is emerging. Energy meters are soon to be introduced as an on-line, instant BTU meter. They will not provide analysis in the manner of the existing GC’s, but they will provide immediate BTU values. This new technology will fill a current void in real-time billing and plant operations. Their value is in reduced costs compared to on-line GC’s, reduced maintenance and calibration costs, and in providing real-time information for operations.

Transportation

The transportation of natural gas samples is a very important issue for both the companies that are involved and the individual personnel who are transporting the samples. The United States Department of Transportation (DOT) covers the transportation of samples in CFR-49. Everyone involved in transporting sample cylinders and other sampling apparatus, both to and from sample collection locations, should be familiar with the rules and regulations set forth in CFR-49.

As well as the safety issues, markings and forms that are to be filled out for DOT purposes, other considerations should be addressed as well. Among these are:

Proper tagging of the cylinder for time, date, location of the sample

Pressure and temperature of the pipeline source

Technician who took the sample

Method used to obtain the sample

Plugging of the valves and checking for leaks prior to transport

Protection of the cylinder and sample apparatus during transport, both to and from the sample location

Temperature concerns during transport, both to and from the sample location – if necessary or required

Other company procedures that will assist in the success of a quality sample being delivered to the laboratory for an accurate analysis.

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Conclusion

The methods, techniques, and designs of today's sampling systems should be considered by every producer, shipper, buyer and end-user. Regardless of the application or installation, there is a system which meets your needs, and will affect your company in the profit and loss column. Sampling and metering are the cash register of your company. Sampling is an art! Examine your methods, procedures and needs closely.

References

"Proper Sampling of Light Hydrocarbons", O. Broussard, Oil and Gas Journal, September 1977

"Standard Cylinder vs. Constant Pressure Cylinders", D. J. Fish, Gas Industries, January 1994

"Analyzing Heating Value", T. F. Welker, Pipe Line Industry, October 1990

"Natural Gas Sampling", T. F. Welker, Presented at AGA Annual Meeting, Anaheim, California, 1981

"Methods, Equipment & Installation of Composite Hydrocarbon Sampling Systems", D. J. Fish, Presented at Belgian Institute for Regulation and Automation, Brussels, Belgium, 1993

“Practical Considerations of Gas Sampling and Gas Sampling Systems”, D. J. Fish, Pipeline and Gas Journal, July 1997

"Selection and Installation of Hydrocarbon Sampling Systems", D. A. Dobbs & D. J. Fish, Presented at Australian International Oil & Gas Conference, Melbourne, Australia, 1991

“The Importance of Discerning the Impact of New Measurement Technology”, D. J. Fish, Presented as Keynote Address, 25th Annual North Sea Flow Measurement Workshop, Oslo, Norway, October 2007

Various Standards of AGA, GPA, API, ASTM and ISO

DJF/2010.ngst

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SAMPLE SYSTEM DESIGN CONSIDERATIONS FOR “ONLINE” BTU ANALYSIS

Matthew Kinsey, Cherokee Measurement & Control

Introduction

The reliability of readings from analytical devices is completely dependent upon the integrity of the sample being representative of the flowing gas. In order to ensure the validity of the sample, measurement personnel should have an understanding of how processes involved with sample extraction, pressure reduction, sample temperature stability, and sample transport time impact the sample integrity. This presentation will discuss considerations in the proper design of sample conditioning systems.

It has long been recognized that the largest source of error in the analysis of natural gas is the sample conditioning system (SCS). The SCS consists of all the components through which the sample gas travels from its source, typically a pipeline, to the gas chromatograph (GC) inject valve. The purpose of the SCS is to extract a natural gas sample that is representative of the source, condition it so it is compatible with the analyzer and transport it to an “online” GC.

What is “Conditioning”?

Conditioning consists mainly of excluding unwanted liquids and solids, regulating pressure and flow, and heating the sample to maintain the sample gas well above its hydrocarbon dew point temperature. During the entire sample conditioning process the sample gas must not undergo any changes in its composition.

This presentation will cover the SCS basic tasks, pertinent industry standards, underlying science involved and the basic design of natural gas sample conditioning systems.

The first task for the SCS is to extract a representative natural gas sample. The definition of “representative sample” has been the subject of much debate in recent years. The central area of disagreement has centered around whether or not liquid in the source should be included in the sample gas. In short, there is no current technology available in the world suitable for extracting a sample of natural gas having the same proportion of liquid as exists in the source gas. Liquid can be present in the source gas as a film on the inner pipe wall and/or flowing along the bottom of the pipeline. The distribution of liquid which is present as a droplet, film, or flowing stream is generally not known. Therefore sampling only the “entrained” droplets would not be representative of the total liquid present in the source gas.

API 14.1 DEFINITION OF A REPRESENTATIVE SAMPLE

The API 14.1 standard “Collecting and Handling of Natural Gas Samples for Custody Transfer” by virtue of its scope specifically excludes multi-phase flow (free liquid and gas) or supercritical fluids. The standard also states that it applies only to natural gas samples which are at or above their hydrocarbon dew point. However, in the standards appendix B.1 the recommended procedure is to eliminate the liquid from the sample point.

The conditions upon which the liquid is to be eliminated is unfortunately not stated. For those well versed in hydrocarbon vapor/equilibrium characteristics it is obvious that unless the liquid is excluded at the pipeline pressure and temperature conditions, the composition will be distorted.

This can be substantiated by reviewing the GPA 2166 standard ”Obtaining Natural Gas Samples for Analysis by Gas Chromatography.”

Sample Extraction

Sample Probes are designed for the purpose of directing a representative portion of the natural gas sample source in the pipeline to the sampling system. The probe extends into the pipeline to ensure a representative sample that is free of unwanted contaminants that may have collected on the interior pipe wall. Sample probes may be designed as fixed or as insertable and retractable units. Regulating probes are commonly used with continuous sampling systems designed to deliver gas to the sampling system at reduced pressure. This allows for the source gas flowing across the pressure reducing section of the probe to prevent excessive Joules-Thompson (J.T.) cooling of the sample gas as the pressure is lowered. Excessive cooling of the sample could cause condensation of some hydrocarbon components in the sample gas thereby altering its composition. A pressure regulating probe with membrane tip is equipped with a phase separation membrane tip which eliminates entrained liquid from the sample gas before it enters the probe’s pressure reducing valves. Liquid rejected in this

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manner drains into the source gas. This prevents sample distortion which would otherwise occur if liquid were present during pressure reduction. The membrane tipped probe can be used to remove hydrocarbon liquids, particles, amines, glycol, compressor oil, etc. Pipelines that are operating at or near the gas stream’s dew point may require special probes designed to overcome the problems of condensation in the gas. API 14.1 states that the sample system be maintained 30 degree above the hydrocarbon dew point at all times.

The hydrocarbon dew point (HCDP) is a combination of temperature and pressure where the hydrocarbon liquid will begin to condense from a gas mixture. Typically, when someone references HCDP, they are referring to the “temperature” that corresponds with a specific “pressure”. For example, they may say the HCDP is 50F at 900 PSIG. Keep in mind that the HCDP temperature for a given composition will vary, depending on the pressure.

API 14.1 requires the determination of the hydrocarbon dew point for any natural gas stream being sampled by use of:

a. Hydrocarbon dew scope (chilled mirror)

b. Historical Information (test well data)

c. Equation of state (EOS) software. The accuracy of the calculated HCDP depends on the type of EOS selected to perform the computation as well as the accuracy of the composition entered into the software.

What does this tell us?

Knowing the HCDP of the sample helps to determine if there are liquids in the source gas OR if liquids are likely to occur in the SCS.

Pressure Reduction

The following questions need to be answered in order to select the proper type of regulator:

a. Can an insertion regulator be used at this sample point or will it require an external, heated pressure regulator?

b. If an external heated regulator is required, will a single stage regulator work or does it need to be a multi-stage regulator?

Probe Length

It is industry practice that the collection end of the probe be placed within the approximate center one-third of the pipe cross-section. While it is necessary to avoid the area most likely to contain migrating liquids, the pipe wall, it may be necessary to limit the probe length to ensure that it cannot fail due to the effects of resonant vibration.

Probe Location

The probe location recommended by the API 14.1 and GPA 2166 standards is vertical mounting at the top of a straight run of horizontal pipe. For gas streams not near the hydrocarbon dew point, essentially any probe location will suffice as long as it does not interfere with the performance of a primary metering element.

For streams that are at or near their hydrocarbon dew point (either continuously or only during process upsets), the probe should be at least 5 diameters (of the maximum diameter of the disturbing element) downstream of that disturbance. This requirement is intended to avoid the effects of liquid droplets or liquids formation due to the impact of the flowing stream on the disturbing element. The probe should not be located in any “dead-end” section of pipe where gas is not continually flowing.

Transporting the Extracted Sample

Once a vapor sample of natural gas has been extracted from the pipeline it needs to be transported to the GC. The recommended material of construction for the process tubing is either 304 or 316 stainless steel. During transportation of the sample, condensation of the gas components must not occur. It is important to maintain the sample gas above its hydrocarbon dew point temperature (HCDP) at all times to prevent condensation from occurring. When ambient temperature is likely to dip within 30 degrees F of the hydrocarbon dew point temperature then heat tracing the sample is required. It is also important to minimize the sample line internal diameter as well as the distance between the sample take off point and the analyzer. This reduces sample transport time.

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Analyzer Protection

It is important to filter the sample flowing into the GC sample loop/inject valve in order to remove solid and liquid contaminants. This filtration should be performed “at” the GC as close as possible to the sample inject valve. The reason being that although upstream filtration may have removed particles and liquids, that may be present in the sample gas “at” the analyzer. Liquid can be present due to condensation of heavy hydrocarbons in the event of upstream filter failure or loss of heat tracing.

Coalescing filters and phase separation membrane based separators may be utilized for filtration at the inject valve location.

If liquid hydrocarbons are present in the sample gas anywhere downstream of the sample probe, the sample is invalid and analysis results should be discarded. Filtration for removal of liquids anywhere external to the pipeline should be for analyzer protection only.

Calibration Gas Considerations

It is important to know the dew point of the calibration gas and always maintain 30 degrees F above the dew point when in service. This will also reduce adsorption of heavy molecules on the inner cylinder walls. If the cal gas drops below the dew point, the heavy hydrocarbons will condense in the bottom of the cylinder. If gas is withdrawn under these conditions, the gas composition will no longer be valid.

Carrier Gas Considerations

The carrier gas supply must be regulated to provide a constant and uniform flow of gas through the columns. Helium cylinders are typically filled to 2,640 psig at 70 degrees F. Carrier gas should be at least zero grade with a purity of 99.995%. Changeover manifolds with stainless steel diaphragms are highly recommended to allow for change out of empty cylinders without interruption to carrier flow. If carrier gas pressure/flow is not maintained as constant, the speed of the carrier gas flowing through the columns will change, causing the speed at which the sample is carried to also change. This in turn causes the peaks on the chromatograph to shift and those peaks may then be mid-identified and/or integrated inaccurately. Either of these events causes inaccurate quantization of the constituent and results in heating value calculation error.

Conclusion

It must be recognized that a properly designed sample handling system is crucial to the correct operation of any “online” BTU analyzer. When there is only a single GC on a custody metering station, the downtime for a GC must not only be at a minimum but it should be planned ahead of time rather than occurring only when a failure has occurred. The reliability and accuracy of the analyzer is totally dependent upon the sample being clean and dry.

REFERENCES

Mayeaux, Donald P. “Fundamentals of Sampling Natural Gas for BTU Determination” , ISHM, 2009

API, Manual of Petroleum Measurement Standards, Chapter 14- Natural Gas Fluids Measurement, Section 1-Collecting and Handling of Natural Gas Samples for Custody Transfer, Sixth Edition, February 2006

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MODULAR SAMPLE CONDITIONING SYSTEMS FOR NATURAL GAS ANALYSIS

Jay St. Amant, A+ Corporation

Introduction

Prior to 1992, analytical sample conditioning systems consisted of components mounted to a back plane and interconnected with pipe and tubing. This type of construction required a large amount of space. The interconnecting tube and piping had a large internal volume and were difficult to purge. To make matters worse, the components, for the most part, were originally designed for pneumatic and hydraulic service and modified for analytical sample conditioning. One might say that the systems were not "analytically correct".

Analyzer designs improved rapidly but the sample system designs were slow to change. Although sample systems have improved substantially, they still are the weak link in "on line" analytical systems.

This presentation will discuss the advancements in analytical modular sample systems, including the miniaturization and modularization of components and systems. Long-term ownership costs and enhanced system performance will be discussed, as well as the ease of maintenance. Analytical sample conditioning systems are becoming “smarter”, and are starting to have the ability to monitor and control operating conditions remotely. Modular technology will be discussed as being the answer to the need for smarter, higher performing, analytical sample conditioning systems.

History

1992: A+ Corporation filed for patent protection of an analytical modular stream switching valve system. The modular valve technology was purchased by Swagelok®.

1994–1999: A+ Corporation filed for patent protection of several analytical modular sample systems related technologies. Refer to Reference 1 for a list of patents which issued. In an effort to promote the modular base/component concept of constructing analytical sample systems, a forum was sponsored and funded entirely by A+ Corporation. It consisted of a representative cross section of petrochemical and refinery personnel involved in improving analytical sample conditioning systems. (Reference 2) It should be noted that some elements of industry were promoting a "stick" approach to sample system construction. The "stick" approach was in use at that time for constructing gas delivery systems utilized by semiconductor manufacturers. It consisted of components "welded" together in series which resembled a "stick".

1999-2000: ISA subcommittee was formed. 2002: ISA subcommittee rapidly produced the ANSI/ISA-76.00.02-2002 specification. Progress towards

commercialization required the collaboration of many companies including substrate vendors, component manufacturers and end users. The Center for Process Analytical Chemistry (CPAC) of the University of Washington provided an umbrella organization where detailed technical discussions could take place in a neutral public forum.

2002: CPAC termed this initiative “NeSSITM

” (New Sampling/Sensor Initiative) and set forth three generations with the first generation comprising a common small footprint high-performance substrate or platform with the goals of reducing costs to build and operate and at the same time increase sample system integrity and reliability. Three major companies supply Modular Sample Systems to pharmaceutical, petrochemical and refinery industries: Swagelok®, Parker, and Circor.

Figure 1 - Typical Modular Sample System (compliments of Circor)

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Modular Advancements and Enhancements – Reference 1 – A+ Corporation Patent 5,841,036 Filed 1996

1) Size Conventional analytical sample conditioning systems require large spaces (typically large panels in an analyzer shelter) which is very valuable in process areas. Modular Sample Conditioning Systems reduce the space required and therefore reduce the costs associated with it. Sample systems can now be housed in small enclosures and heated with solar powered heat.

2) Labor Configuring, mounting, and interconnecting of conventional sample conditioning systems is very labor intensive and in some cases requires skilled labor for specialized tube bends and configurations. Modular systems do not require any tube bending and therefore significantly reduce labor costs.

3) Excessive Internal Volume Large internal volumes and static dead volumes have a negative impact on the performance of an analytical sample conditioning system. Conventional systems are plagued by these large dead volumes and require large amounts of gas to sweep these cavities which leads to large bypass and vent flow rates. Modular systems reduce or eliminate these cavities and reduce the overall system volume requiring less bypass and less vented gas. Lowering the vented gas moves the sample conditioning system toward the new “green” policies.

4) Connections and Fittings Conventional systems require fittings and tubing connections between components. Modular systems eliminate the requirement for fittings and tubing connections and therefore eliminate the possibility of leaks at those connections. All components are designed for surface mounting to the modular board. Therefore adding or replacing components is fast and simple.

NeSSI

TM GEN I – True Costs – Excerpt from “History of ISA SP76 and NeSSI.doc” – Reference 2

Papers by John Sablatura, Jeff Gunnell, and Peter Van Vuuren discussed true cost of ownership. They envisioned field-mounted and self-contained integrated analyzers and sample systems that would be “Smart” (incorporating diagnostics and control) with “Plug and Play” maintenance.

They analyzed project data and determined 38% of the initial outlay is spent on the process analyzer, 30% on the sample system and 27% on providing a controlled environment for the process analyzer and its sample conditioning system. They forecasted that a savings of 40% of the “Cost of Build” could be achieved by

reducing the cost of the sample conditioning system reducing the cost of the sample transport system eliminating the need for a climate-controlled analyzer house

They also forecast that a savings of 35% of the “Cost of Ownership” could be achieved by increasing the number of analyzers a technician can support eliminating the need for a dedicated site analyzer engineer reducing the cost of spares holding

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Jeff and Peter thought that technology had evolved to the point where the following could be accomplished on a cost-effective basis

modular sample systems (subassemblies of functional blocks) open communication architectures (seamless LAN interconnectivity). sensor-on-chip technologies (small and rugged analyzers)

GEN I - New Modular sample conditioning concept designed specifically for Natural gas

Background

The original and current modular systems are designed for flexibility, which is desirable when applied to pharmaceutical, petrochemical, and refining industry applications. This flexibility is desirable due to the extremely wide range of applications in these industries. By comparison however, Natural gas has a very narrow application range.

The flexibility, afforded by currently available modular systems, complicate the task of designing, selecting, and constructing a Natural Gas sample system. To achieve flexibility many components are utilized to produce countless configurations. The truth of the matter is that a small number of design configurations can accommodate most Natural Gas applications.

A new design approach is a modular system which utilizes a single board to interconnect all sample conditioning components. This approach significantly reduces the number of components, and therefore the design complexity.

Modular Sample conditioning system for Natural Gas

This new design consists of a single board having all of the required components mounted on its surface. (Refer to Figure 3). The major benefits of utilizing a single board over current modular designs are that:

a. it is more compact therefore easier to heat and more portable

b. the learning curve required to design with other current systems is eliminated

c. a single plane surface makes it easier to troubleshoot

d. flow diagrams can be imprinted on the board's surface to facilitate troubleshooting

e. it will encourage the production of "standard" systems

Above all, the sample conditioning system becomes a "component". The entire system can be replaced in minutes.

Figure 3 – Single Base Board Modular System

The Primary Board shown in Figure 3 is designed for a single stream and one calibration gas and is normally used for Gas Chromatographs. Attached to it is a Stream Adder Board. The sample system can be unplugged from its Dock and replaced should it become contaminated or need to be checked for functionality. The Dock remains in the field along with all tubing connections and integral valves. The schematic for this sample system is shown in Figure 4.

Stream Adder

Primary Board

Dock

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Figure 4 – Single Stream and Cal Gas on Primary Board and Stream 2 on Stream Adder Board

Features and Benefits

Fluid passages are formed internal to the modular board. Therefore internal volume is reduced, dead volume is eliminated and tubing, piping, and fittings are no longer required for component interconnections.

Going Green - Lower internal volume means less volume to purge and vent.

Single piece modular board with fluid passages formed in a predetermined arrangement. This eliminates the need for designing and building a base system from a large number of "erector set" base parts. It is also easier to follow the fluid path and troubleshoot than then current systems and occupies less space. The entire system can easily be heated. It may now be possible to "solar heat" the sample system.

Low volume fittings (LVF) can be utilized for tubing connections to and from the modular board. This provides a "straight through", easy to purge fluid passage. Refer to Figure 5.

Figure 5

Single board modular construction is easy to install or replace. Entire sample systems (modular board) can be replaced in minutes if required. Boards can be returned to the "analyzer shop" or manufacturer for

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testing and/or repair. Replacing components or the entire sample system is similar to replacing electronic PC boards.

Field problems can now be corrected by technicians of limited experience. Sending a system out to be repaired is much less expensive then having a manufacturer's service technician perform "on site" repair. With standardized system boards the user can stock spare sample systems for quick replacement.

Additional streams can be added to the primary board. This makes it possible to easily expand the number of sample streams after field installation.

NeSSITM

Gen II – Smart Sampling/Connectivity Bus

The next phase of modular sampling conditioning systems is the second generation (Gen II) of NeSSITM and it brings electronics to the modular sample system including intrinsically safe digital communication.

Gen II brings wired or possibly wireless technology to carry all signals to operate valves and monitor/control flows, pressures, and temperature. These smarter integrated systems are driven by lower cost to own. Many of these features have been available on the analyzers but not on the analytical sample systems.

Sensors currently available include those that: monitor and control flows monitor and control pressures monitor temperature monitor differential pressure across filter elements

Networked connectivity to these sensors means that they can be monitored and controlled remotely. Alarms can also be monitored and set remotely. Modular switching valves like stream/cal and SSO/ARV can also be switched remotely. These features are very beneficial for centralized control and monitoring as well as very important for remote access locations. Heaters could be turned off during extended periods of warm weather or set points changed or adjusted.

Other benefits related to technicians include: (Reference 5) Local/remote lockout is possible with remote control of pressures and flows and valves Continuous monitoring of the sample system is now possible automatically so that upsets can be handled

immediately instead of waiting for periodic spot checks by the technician Validation procedures can be remotely initiated during upsets, holidays or other times of lowered

maintenance or when technicians are not available Remote location preventative and predictive maintenance is also now possible Technicians can now be better prepared for possible maintenance with standardized spares that can be

exchanged.

Three bus technologies are currently available to provide networked connectivity to components and sensors mounted on the substrate in Class I Div I locations: IS CANbus, Siemans I2C, IS Modbus. (Reference 4) NeSSITM envisions a smart – Sensor Actuator Manager (SAM) as the interface between the NeSSITM bus and the EtherNet enabling communication with a DCS or SCADA: Supervisory Control and Data Acquisition. (Reference 2)

Gen II Examples

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GEN II – Future possibility - Modular sample conditioning concept designed specifically for Natural gas

The single board modular construction technique facilitates a future concept that would allow the wiring to be hidden inside the board and the conduit connections to be made at the dock.

All fittings, tubing, conduit, and wiring are in the Dock

Electronic modules can replace the flow meters and regulator.

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NeSSITM

GEN III – Seeks to move the analyzers out of the analyzer houses and shelters and closer to the process.

The future of NeSSITM is the third generation analyzer initiative (Gen III) which seeks to bring the analyzer out of its dedicated climate-controlled walk-in shelter, reduce its size (often times while increasing its performance due to microprocessor logic capabilities), and place it down onto the modular sample system. (Reference 2)

References

1. Patent 5,305,788 filed August 13, 1992, issued April 26, 1994

Patent 5,361,805 filed February 14, 1994, issued November 8, 1994

Patent 5,841,036 filed August 22, 1996, issued November 24, 1998

Patent 6,122,825 filed November 18, 1998, issued September 26, 2000

Patent 6,457,717 filed September 22, 2000, issued October 1, 2002

2. http://www.cpac.washington.edu/NeSSI/NeSSI.htm

http://www.cpac.washington.edu/NeSSI/History%20of%20ISA%20SP76%20and%20NeSSI.doc

3. CPAC Fall Meeting 1999; Presentation by Donald P. Mayeaux titled "Modular Sample Conditioning System"

4. http://www.cpac.washington.edu/NeSSI/41_IFPAC_2010/presentations/plowery-IFPAC-2010-CIRCOR_NeSSI_status.pdf

5. http://www.cpac.washington.edu/NeSSI/41_IFPAC_2010/presentations/Farmer_NeSSI%20Applications_c.pdf

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ANALYTICAL DEVICES FOR THE MEASUREMENT OF WATER VAPOR AND HYDROCARBON DEW-POINT IN NATURAL GAS

Daniel R. Potter, AMETEK Process Instruments

Introduction

The determination of water vapor (water dew point) is crucial in the processing, custody transfer and transport of natural gas. High levels of water vapor in a natural gas stream can lead to a number of problems which include the formation of hydrates and the contribution to corrosion of plant and equipment. Furthermore, water vapor present in natural gas streams affects the overall quality of the gas, making the measurement of water vapor in natural gas an important requirement to producers, suppliers and end users in the industry.

Equally important is the need to determine the hydrocarbon dew point temperature in a natural gas sales pipeline network. The formation of hydrocarbon liquids (condensate) due to the presence of heavier hydrocarbons in the natural gas can lead to increase pressure drops in the pipeline system, flooding and safety hazards associated with liquids such as hot spots on compressor turbine blades.

There are a number of ways of determining the water vapor concentration in natural gas, and the various suppliers of the analytical technologies utilized have spent many years developing, improving and optimizing their analyzers to provide accurate, reliable and robust solutions for their customers.

AMETEK Process Instruments has been in the business of moisture analysis and hydrocarbon dew point determination for the natural gas industry for nearly four decades, and has pioneered the development of many on-line devices used for the detection of water vapor in many industrial applications. This paper presents a brief review of the most common methods and technologies used for the determination of water vapor, water and hydrocarbon dew point temperatures in natural gas applications.

Water Concentration vs. Water Dew-Point Measurement The dew-point of a gas is a physical property; the temperature at which the sample gas becomes saturated and condensation first begins to appear. At this temperature, the gas exists in equilibrium with a condensed phase. Although the term dew-point is used in a generic sense, strictly speaking, the dew-point temperature refers to the equilibrium established over a liquid phase. In the case of water vapor measurements, temperatures below zero degrees Celsius typically refer to equilibrium over a solid phase (i.e., ice), so the term frost-point is used. Because the vapor pressure over a solid phase is lower than that over a liquid phase, the dew- and frost-points of a sample gas are not equivalent. The discrepancy between the two increases as the temperature decreases. Because the dew/frost-points are the result of thermodynamic equilibrium between two phases, they will not only be a function of the component concentration (e.g., hydrocarbon or water), but also the sample pressure and the sample gas composition. Thus, while the concept of a dew-point has a direct physical meaning, correlating this property to the component concentrations is not so straightforward.

There are two classes of measurement devices. Devices capable of determining the physical dew point of either a hydrocarbon or water in natural gas, and those devices which are capable of determining or measuring the concentration of water in a natural gas sample.

Analyzers capable of measuring the dew-point temperature directly are based on chilled mirror technology and are sometimes referred to as „first principle‟ devices. Expressing water content in terms of dew-point originates from this first principle device tracing its history back to the early dates of the natural gas industry when the U.S. Bureau of Mines developed the manual chilled mirror device.

The other class of measurement devices used for the determination of water vapor in natural gas determine the concentration of water vapor or partial pressure of water in the natural gas sample. Common concentration or content outputs of these devices include mg/Nm3, lbs/mmscf and parts per million either by weight (ppmw) or volume (ppmv). Water vapor measurement technologies most commonly used in the natural gas industry include capacitance-based sensors, Quartz-Crystal-Microbalance (QCM), Tunable Diode Laser Absorption Spectroscopy (TDLAS) and electrolytic-based sensors (also referred to as P2O5). These technologies will be discussed in more detail in this paper.

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The accepted conversion between the measured concentration of water vapor and dew-point temperature is based on empirical data from the original research of the Institute of Gas Technologies (IGT), published in the 1950‟s in IGT‟s Bulletin No. 8, and republished in the American Society for Testing and Materials (ASTM) standard ASTM-D1142-95. More recently, a European calculation adopted by the European Gas Research Group (GERG) and published by the International Organization for Standardization Society (ISO) as method ISO 18453:2004 specifies a method to provide users with a reliable mathematical relationship between water content and water dew point in natural gas.

Chilled Mirror Hygrometry

As previously described, chilled mirrors actually measure a physical property. A chilled mirror consists of means to accurately measure the temperature at which water condenses on a temperature-controlled surface, which is in contact with the process gas. Chilled mirror instruments typically operate by continuously flowing sample gas across a temperature-controlled, polished surface (i.e., a mirror). As the temperature of the polished surface is slowly lowered, formation of condensate is identified visually, either by directly observing the surface of the mirror, or by means of a magnified viewer, which superimposes the mirror temperature on a magnified mirror surface (Figures 1A and 1B). Once the condensate has formed and a “dew-point” temperature has been established, the sample pressure and temperature may be recorded.

Figure 1A and 1B – Examples of Manually Operated Dew Point Chilled Mirror Devices

Chilled mirrors can be classified into two categories, manually operated or automated, on-line devices. Manual devices are typically available at a fraction of the cost of on-line water vapor measurement devices, but require frequent maintenance and experienced technicians to perform the measurement. Mirror cooling is achieved using an external coolant (refrigerant) to reduce the temperature of the mirror to the desired dew point temperature. Careful control of the cooling is required to ensure that accurate and repeatable dew point detection is achieved.

Advantages of the manually operated chilled mirror device includes the ability to detect both water and hydrocarbon dew-points, provided there is enough separation between the two condensation temperatures, and that one of the dew-points does not obscure or wash off the other. Generally the detection of multiple dew point temperatures using a manually operated chilled mirror is reserved for experienced technicians trained to distinguish between water, hydrocarbon or other potential condensable in a natural gas stream. Figures 2A and B highlight the differences in appearance of hydrocarbon and water dew point „stains‟ on the surface of a manually operated chilled mirror device.

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Manually operated chilled mirrors are generally designed to require very little set-up time by the user. AMETEK‟s line of Chanscope Dew Point Testers require no external power, are very light weight, suitable for monitoring water dew point temperatures in sour gas applications (high H2S applications) and come completely assembled and ready-to-use.

Figure 2A - Water Dew Point with Chilled Mirror Figure 2B - Hydrocarbon Iridescent Ring (Dew Point)

The major disadvantage of using manually operated chilled mirrors is that manual devices require experienced operators to make reproducible observations of condensate formation. Natural gas streams may also contain components which could condense and cause erroneous dew-point temperatures for the water and hydrocarbon dew-points (e.g., glycol, amines, and methanol). Inexperienced operators of manual devices frequently „call‟ water-like condensable substances on the surfaces on the mirror water, when in fact the condensable may be a methanol or a glycol. Manually operated devices are non-continuous and are typically only used to perform spot checks to ensure a pipeline specification is met, or to verify readings and confirm the operation of continuous moisture analyzers installed on natural gas pipelines.

Automated chilled-mirror devices generally follow the same “direct” measurement criteria as do manual devices. The mirror is cooled by either thermo-electrical coolers (Peltier elements) or external coolants such as natural gas or CO2 (Joule-Thompson cooling). A well-designed electronic cooling system will allow for stable and exact temperature control and is generally preferred. The detection of condensate is achieved using electro-optical detection systems, typically consisting of a combination of light-emitting-diodes as the source, and phototransistors as the detectors.

The construction of the mirror for water dew point detection generally follows the same criteria as for the manually operated devices, a smooth reflective mirror constructed of material which is resistive to corrosion and with good thermal characteristics. The thermo-electric cooler is close-coupled to the mirror assembly, which is in contact with the flowing gas. Highly accurate temperature devices (e.g. PT 1000 RTD) embedded within the mirror measure the temperature of the mirror surface.

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Figure 3 - Automated Chilled Mirror Analyzer For the measurement of hydrocarbon (HC) dew point, the optical surfaces of the mirrors may be modified to take advantage of the different wetting properties of the hydrocarbon components, as compared to water. Because of the high surface tension of water, condensate will form in droplets on the surface. Hydrocarbon condensate spreads into a thin reflective film due to lower surface tension. To measure the HC dew-point, a rough, semi-matt surface is typically used as the condensation surface. As hydrocarbon condensation occurs on the optical surface, it becomes reflective, and detection of the hydrocarbon dew-point is made.

Automated chilled mirrors provide a number of key features and benefits compared to their manual counterparts. Integrated electro-optical detection systems eliminate any bias associated with the measurements, providing a consistent, accurate determination of dew point temperatures. Thermo-electric cooling systems provide the means to control the cooling rates of the chilled mirrors, enhancing sensitivity and providing more accurate „first stain‟ detection. Finally, automated chilled mirrors provide a continuous update of dew point temperatures without requiring continuous supervision or intervention by experienced technicians.

The major drawbacks of the automated chilled mirror devices are initial cost of the systems. Automated chilled mirrors generally require sample systems and some environmental control (installation in enclosures or shelters) to operate properly.

Capacitance Sensors

Capacitance sensor is the general term referring to the use of metal oxide, ceramic, or polymer films as a moisture-sensitive dielectric sandwiched between two electrodes. The most common example in industry is the aluminum oxide type. This sensor consists of an aluminum substrate upon which a thin layer of aluminum oxide is chemically formed. A thin layer of gold is then deposited on top of the aluminum oxide, which acts as the top electrode of the capacitor. The gold layer is thin enough so the water molecules can readily permeate through and enter the aluminum oxide layer below. Water molecules entering the aluminum oxide layer change the dielectric constant of the layer, and thereby change the capacitance of the sensor. The water vapor pressure is then monitored as a function of the capacitance of the sensor.

In practice, the sensor element is shielded with a porous sintered-metal sheath, which forms the tip of a probe assembly. The sensor is connected to remote electronics via signal cable. Although this probe design is suitable for in-situ operation, it is common practice to install them in an extractive sample system. Typically, one or more probes are installed on a manifold so a sample of the natural gas can be conditioned to remove contaminants, and the pressure can be regulated. This design allows for the probes to be removed, or isolated from the process, as required for maintenance.

The primary advantage of capacitive-sensor-based probes is low installed cost. These sensors also have some significant weaknesses. Specifically, any material in the sample gas that can coat, or foul, the sensor element will effectively prevent the sensor from contacting the sample gas (i.e., the readings from the sensor remain constant,

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independent of the changing moisture concentration in the sample gas). Aluminum-oxide sensors calculate dew point based on the water that has permeated through the metallic electrode and been absorbed by the dielectric material. These sensors can only provide an accurate representation of the process gas after the moisture within the sensor has reached equilibrium with the moisture in the process gas.

Figure 4A and 4B - Capacitance Probe Assembly and Operation Quartz-Crystal Microbalance Sensors The Quartz-Crystal Microbalance (QCM) sensor has been used for water vapor measurements since the early 1970s. There have been numerous advancements made to the technology since then which have provided dramatic performance improvements.

Quartz Crystal moisture analyzers are fairly simple and straightforward operating devices. At the heart of the technology is a simple quartz-crystal oscillator. To fabricate the sensor, a portion of the quartz crystal is coated with a hygroscopic material. Figure 4A illustrates the QCM cell construction and figure 4B and C highlight the basic operation of the QCM system. When exposed to a sample gas containing water vapor, the hygroscopic layer will adsorb water from the gas phase, thereby increasing the mass loading of the quartz crystal. This increase in mass decreases the resonance frequency of the oscillator; the moisture concentration is measured as a function of the frequency change. The QCM sensor technology is incorporated into an extractive sampling system, which is used to alternately expose the sensor element to the sample and a dry reference gas. The moisture concentration is then measured as a function of the difference in oscillator frequency measured for the sample and reference streams.

Figure 4A – QCM Cell Assembly Figure 4B and C – QCM Operation (Sequence of Dry and Wet Measurement Cycles) The measurement does not require the sensor to come to equilibrium with the moisture in the sample gas, resulting in relatively fast speed of response to both increasing and decreasing moisture concentrations. Materials that stick to, or foul, the sensor will cause a shift in the oscillator frequency, but will not substantially influence the frequency difference recorded between the sample and reference gases, making these sensors more resistant to contaminants found in natural gas streams. In a typical QCM-based analyzer, a means of testing sensor performance (i.e., a permeation device to produce known moisture challenges) is built into the sample system to eliminate the need for removal and remote testing of the sensor. The moisture measurement is made under controlled operating conditions by keeping the temperature, pressure and flow of the analyzer constant. The non-equilibrium based approach is a major advantage of QCM technology, when compared against other contact sensor approaches. In an equilibrium-based sensor, the speed of response depends on the magnitude of

C0

C2

R1

R0

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the change in measurement value. A large step change will result in a big difference in the partial vapor pressure of the water molecules and the sensor will respond relatively fast. If the change is small, the sensor takes much longer to equilibrate because of the small differential in the water vapor pressure. With a non-equilibrium based sensor, such as the QCM, every measurement cycle looks at a big signal even if the change in the measured value is small because a difference between a dry reference gas (a small signal) and wet sample gas (a big signal) is observed. The end result is a fast response to the rate of change in the moisture concentration.

Additionally, the exposure of the sample to a cleaner (and in some cases pre-conditioned) „reference‟ gas stream minimizes the amount of time the sensor is exposed to „dirty‟ gas. Dual mode sensor calibration is provided and users can choose to have the sensor exposed to cleaner reference gas for extended time periods (sensor saver mode).

These devices are widely applicable in the natural gas market, due to the inherent accuracy of the measurement technology. QCM analyzer technology is extremely sensitive and capable of providing measurement accuracies of +/- 10 ppb for low concentration water vapor analysis operation in natural gas processing applications such as cryogenic turbo expansion, LNG processing and other low-level detection applications typically requiring extremely low levels of moisture.

Figure 5 – QCM Performance Capability, Moisture Challenge of 6 ppb(v) and Analyzer Response

0 5 10 15 200

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Figure 6 – QCM Analyzer Performance Data for Low Concentration Moisture Measurement at Outlet of Molecular Sieve Dryer (Cryogenic Natural Gas Processing), Response to a 10 ppb(v) Challenge

Electrolytic Sensors

Electrolytic moisture sensors have been in use since the late 1950‟s and were among the first on-line water vapor analyzers available to industry. They continue to be in service today due primarily to their simplicity and selectivity for detecting water vapor, and the fact that the technology, in theory, is considered to be a „first principles‟ device. DuPont Analytical (now AMETEK Process Instruments) was the first company to offer these devices, and the instruments were first developed to measure water vapor concentrations in gases that liquefy at higher temperatures (freons).

The analytical cell of the instrument is constructed from two co-helically wound platinum wires that are embedded on the inside surface of a small-diameter glass tube. The surface of the sensor is coated with phosphoric acid (P2O5). With the sensor maintained under a DC potential, the P2O5 serves as a hygroscopic substrate for the absorption and electrolysis of water molecules. Figures 7A and B show the basic construction of an electrolytic sample cell. The water molecules entering the cell are converted into hydrogen and oxygen, and the electrolysis current required for the conversion is measured. Because the total flow of sample gas is controlled, the application of Faraday‟s Law yields the concentration of water vapor in the sample gas.

Figure 7A and B – Basic Operation of Electrolytic (P2O5) Moisture Analyzer

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The advantages of electrolytic sensors are their simplicity and “first principles” performance. Moisture analyzers that use electrolytic sensors are typically small and light enough to be portable, and some commercially available instruments are designed to be battery powered. The primary weakness of the electrolytic sensors is their erroneous performance on sample streams containing hydrogen or oxygen. The presence of high concentrations of these gases in the sample can lead to recombination. Specifically, the hydrogen and oxygen formed in the electrolysis of water entering the sensor can react with the corresponding gas in the sample to form more water. Water molecules formed from recombination are then electrolyzed in the sensor. Because of the recombination effect, it is possible for a water molecule entering the sensor to be “counted” more than once. A second weakness of the electrolytic sensor is that the presence of liquid water in the sample will deteriorate the phosphorous pentoxide coating requiring cell replacement. And finally, the presence of background current in the sensor can add bias to low-level measurements.

Tunable Diode Laser Absorption Spectroscopy (TDLAS)

The measurement of water vapor using this optical (or spectroscopic) technique has received very favorable response from industry for the obvious reasons that these devices employ non-contact sensor technology for the detection of water vapor in natural gas applications. This „non-contact‟ approach significantly reduces maintenance requirements of the instruments and reduces the overall costs of maintaining the equipment. While relatively new to the field of natural gas analysis, laser spectroscopy has been around since the 1960s. It was not until the introduction of near infrared tunable diode lasers (TDLs) that it became practical to design a process instrument with the technology. While conventional infrared (IR) and near infrared (NIR) spectrometers have been used to measure water vapor in different sample gases, their limited wavelength resolution has restricted them to simple sample matrices, where there is not much overlap in the spectra of the absorbing species. The key advantage of the laser spectrometer is the extremely high-wavelength resolution; the emission bandwidths are on the order of 30 megahertz. With this high resolution, a laser spectrometer can be used to monitor a single ro-vibrational transition that is unique to the analyte species, thereby reducing (close to eliminating) the background interference encountered by conventional IR-NIR spectrometers. In addition to narrow bandwidths, the TDLs are ideally suited to perform wavelength modulation spectroscopy (WMS), which yields detection limits that are several orders below a conventional absorption measurement.

Figure 8 – Illustration Showing TDLAS Narrow Emission Bandwidth vs. Conventional IR Techniques

The key advantage of laser spectroscopy is that it is a non-contact sensing technology. The sample never comes into direct contact with the sensor element. TDL spectrometers are capable of fast response. Additionally, the measurement is not flow dependant, but care must be taken to control the sample temperature and pressure. Changes in sample temperature and pressure affect the line shape of the ro-vibrational transitions and will cause changes in the instrument readings.

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A drawback to this technology is the temperature sensitivity of the TDL. The junction temperature of the laser diode is critical to the measurement; any small changes in temperature of the diode will shift the center wavelength of the emission and can result in erroneous measurements or alarm conditions in the analyzer. While most manufacturers use conventional thermo-electric coolers and thermo-couples to maintain a stable temperature of the laser diode, the use of on-board moisture reference cells has been used to provide the TDLAS system with „line-lock‟ capability and provide feedback to the temperature control loop of the TDL to increase reliability and confidence in the measurement. Part of the laser beam is passed through the reference cell assembly where the spectra of the analyte sample in the reference cell is monitored and any shift in the observed peak is used as a feedback signal for the temperature control of the tunable laser diode.

A final disadvantage is the range and accuracy capability of the TDLAS device. While it is acceptable to use these instruments in traditional pipeline natural gas applications, their use for low-level detection of water vapor is limited due to the detection capability in a methane-based background. Specialized techniques such as differential spectroscopy add maintenance, cost and potential errors to the measurement systems.

Figure 9 – A Multi-Component TDLAS Analyzer with On-Board Reference Cell for ‘Line-Lock’

Sample Conditioning Systems

A great deal has been written on sample-conditioning-system components from probes to pressure regulators, filters and sampling lines. There are a number of key requirements to remember when preparing or transporting a sample to water vapor and dew point analyzers.

The following is a list of critical components and key rules of thumb to maintain when operating chilled mirror devices in natural gas applications:

Water is a small polar molecule that will „stick‟ to most surfaces. The adsorption of water onto surfaces in a sample system can cause a substantial decrease in the response speed of a sample system. The lower the water dew point that is to be measured, the more serious the role of adsorption becomes. When a “wet” challenge is

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introduced into a dry sample line, water molecules from the gas phase will populate all of the available surfaces. Those water molecules that are lost to the surface of the sample system are not measured by the analyzer. Conversely, when a dry gas is introduced to a wet sample line, the surfaces will desorb water until equilibrium is reached. Thus, surfaces are responsible for substantial lag times in measuring both increases and decreases in the moisture concentration of the sample.

It is therefore always recommended to ensure that the sample transport line is to be kept as short as possible. For installation of manually operated chilled mirrors, it is generally accepted to use flexible, stainless steel braided tubing suitable for use at higher pressures.

For installation of stationary, automated chilled mirror devices or water vapor analyzers, temperature controlled sample lines are preferred as the surface coverage of a sample system is a function of temperature. Higher temperatures result in lower surface coverage. Insulating and heating the line to 60°C or higher is recommended. However, most important is temperature stability. Process piping takes up and releases water with ambient temperature changes. A sample line with a varying temperature, will exhibit the same behavior (i.e., the moisture measurement will serve as a thermometer for the sample line).

Copper, aluminum, and carbon steel tubes are not recommended because the oxide film on the inside wall surface promotes adsorption. Teflon and plastics are not recommended because these materials will absorb (and later desorb) large quantities of water from the sample gas. The highest quality stainless steel sample line should be used. If the application requires monitoring of very low water dew point temperatures, a very different (and very costly) sample system is typically required. The sample line must be 316L, and be electro-polished. Electro-polishing reduces surface roughness (i.e., reduces surface area) and creates a more inert surface.

Filtration to eliminate or reduce the potential for liquids should be considered. It is common practice to use membrane filters incorporated into the sample systems to protect the equipment from liquid slugs and ensure continuous operation of both manually operated as well as automated chilled mirror devices. Filtration may be installed directly upstream of the manual mirror cell assembly, or remotely installed at the pipeline connection (insertion type filters). Insertion membrane filter designs reduce and remove liquids directly at the source and protect the entire sample system of the instruments.

Pressure regulation, when required for monitoring of hydrocarbon dew point temperatures at the cricondentherm, should take Joule Thompson cooling into account and be designed to ensure that on condensation occurs in the sample system.

Conclusion

Chilled mirror instruments for the detection of water and hydrocarbon dew point temperatures have been used in the natural gas industry for nearly 80 years. The determination of water and hydrocarbon dew points using these devices can provide accurate, reliable and repeatable results, provided they are supplied with a representative sample of the process gas, and in the application and operation of manually operated chilled mirrors, are operated by experienced personnel. Automated chilled mirror hydrocarbon dew point analyzers have been designed for rapid, interference free determination of hydrocarbon condensate in natural gas systems and have incorporated sample systems to minimize sample contamination and operation at fixed pressures.

There are a number of chemical-based, contact-sensor approaches available for the determination of water vapor in natural gas samples, each of the presented technologies have advantages and disadvantages which should be considered when making a decision regarding which technology is the most suited for the process or pipeline application. And finally, Tunable Diode Laser-based spectrophotometric techniques have been introduced for fast, low maintenance and reliable determination of water vapor in natural gas transmission (pipeline) applications.

A properly designed sample system reduces or eliminates the presence of contaminants and ensures proper operation of either type of chilled mirror technology.

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References:

Bear, R.; and Blakemore C.; "Reducing the Detection Limits for a Process Moisture Analyzer”, Proceedings of the 46th Annual ISA Analysis Division Symposium, Volume 34, 2001

Hauer, R.; Potter, D.: “Instruments for Measuring Water Vapor and Hydrocarbon Dew-Point in Natural Gas”, Presented at Canadian School of Hydrocarbon Measurement, 2004

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SAMPLING AND CONDITIONING NATURAL GAS FOR H2S TDLAS ANALYZERS

Sam Miller, SpectraSensors Inc.

Introduction

The H2S concentration is a critical quality parameter for custody transfer in natural gas pipelines. The H2S level is driven by tariffs and off-spec gas usually results in a “shut-in” of an offending source. Additionally, H2S measurements are made in a variety of sweetening plant streams for the purpose of process optimization.

There are several technologies for measuring natural gas with similar sample conditioning requirements; however this paper focuses on TDLAS (laser-based) analyzers, specifically, the sample conditioning requirements. With respect to sample conditioning, the requirements include high speed of response as well as measurement precision which is achieved by maintaining a representative sample from the process stream to the analyzer.

TDLAS analyzers utilize an extractive technique such that the sample is taken off the source which flows continuously through the analyzer. The source pressure is usually between 400-3000 psig and the pressure in the analyzer cell is roughly atmospheric pressure. The effluent typically vents to atmosphere or to a flare. When sampling for on-line H2S analysis it is critical that the sample containing a representative concentration of H2S reach the analyzer in the shortest period of time possible.

This paper will cover the sample conditioning considerations for achieving the best results using a TDLAS (Laser) based H2S analytical system.

Sample Flow Rate

The Model SS2100 H2S analyzer typically uses 3 standard liters per minute (SLPM) through the cell plus an additional 1 SLPM bypass. The analyzers sometimes have an optional built-in moisture measurement (2-Pack and 3-Pack models) which use an additional 1 SLPM.

- H2S Analyzer = 3 SLPM + 1 SLPM bypass (approximately 8.5 SCFH)

- H2S Analyzer with optional H2O/CO2 = 4 SLPM + 1 SLPM bypass (approximately 10.6 SCFH)

Sample System Overview

Figure 1: For the purposes of this discussion, the overall sample system is divided into three main categories; 1) Sample Extraction, 2) Sample Transport, and 3) Sample Conditioning

Sample Extraction

Sample extraction takes a small part of the stream and reduces its pressure altering the sample’s composition as little as possible. The stream composition may need to be altered slightly in some cases in order to make it viable for the analyzer. For example, if the stream is two phase in the pipeline (gas plus liquid), then practically, it is only

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possible to extract the gas portion of the sample. This is the reason that a membrane-tipped probe is recommended.

Recommendations for sample probe:

- Membrane-tipped probe should be used on natural gas pipelines to reduce free liquid in sample

- Install probe on top of pipe 5-8 pipe-diameters from elbows, tees, components, compressors, etc with tip of probe within center third of pipe diameter1

- Choose regulator type (probe regulator vs. external regulator) making sure that the sample will not condense given the specific gas composition, flow rate, pressure drop, gas temperature in the pipe, and gas temperature after extraction.

A probe regulator may be used if continuous flow is expected (many storage facilities have intermittent flow in the pipeline and a probe-regulator is not recommended). Additionally, a probe regulator may only be used only if the gas temperature can be maintained above the dewpoint of the gas sample considering the fact that the sample will cool some as the pressure is reduced. A complete understanding of the phase envelope of the gas sample and the cooling effect of the pressure reducer is required to make this assessment.

Figure 2: Regular probe (no regulator) on left, and probe-regulator on right

If heat must be added to the sample in order to keep it above the dewpoint, then an external heated regulator may be used. Again, the temperature of the sample must be maintained above the dewpoint of the gas (a buffer of 18°F (10°C) is recommended in ASTM D5503. To use an external regulator, a standard (non-regulated) probe with a membrane tip should be used. Figure 2 shows a standard probe and a probe-regulator. Figure 1 depicts a standard probe with an external regulator.

Only “analytically correct” regulators should be used in the sample system (internally wetted surfaces are polished and un-swept volumes are minimized). Do not use standard regulators designed for pneumatic control or pipeline/distribution regulation.

After the sample pressure is reduced, the dewpoint temperature of the sample will be lower than it was at high pressure. However, a heated enclosure over the probe may be required (especially when using an external regulator) to maintain the components and the sample temperature above the hydrocarbon dewpoint (HCDP) and water dewpoint. If the HCDP is being calculated, a 30°F buffer should be used to account for calculation uncertainty.2

Sample Transport

The gas sample transport line pressure should be set such that the sample arrives at the analyzer at approximately 25-45 psig. This is a relatively low pressure and will allow for a relatively short lag time.

1 American Society for Testing and Materials, ASTM D5503, Standard Practice for Natural Gas Sample-Handling and

Conditioning Systems for Pipeline Instrumentation, 2008 2 For more on this refer to American Petroleum Institute API MPMS Chapter 14.1 Collecting and Handling of Natural Gas

Samples for Custody Transfer, June 2001

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The sample transport line length should be minimized to improve overall speed of response. Typically, the sample transport line will not exceed 100 feet. The recommended sample tubing is 1/4-inch stainless steel tubing with electrochemically polished inner walls. Using 1/4-inch tubing results in a time lag of less than 1 minute per 100 ft. The actual lag time depends on line length, pressure, temperature, and flow rate.

Improved response rates can be achieved by utilizing coatings inside the tubing. Figure 3 shows a comparison of various sample transport materials.

Figure 3: Sample line speed of response test using 20-ft lengths of 1/4-inch tubing with a flow rate of 4 SLPM. Materials tested included (from left to right in the graph above): Electrochemically polished and fused-silica coated 316L, Electrochemically polished 316L, Hastelloy C276, Fused silica coated 316L and standard 316L Stainless Steel. Results are shown for 96% of step change from 0 to 100 ppmv and 100 to 0 ppmv.3

The data in figure three shows a significantly favorable improvement in the speed of response of about 20 seconds per 20 feet for a large spike of 100ppmv. Most of this gain can be achieved by using electrochemically polished (EP) tubing with the best result achieved by using EP and fused silica coated 316L.

The explanation of this behavior and the difference is speed of response is the adsorption and desorption of the H2S to the walls of the tubing. Industry wisdom says that heating the sample line will also improve the speed of response by reducing adsorption effects. Additional test are planned in the near future to quantify this. Heated sample transport lines also keep the gas in vapor phase when the sample is exposed to outside temperatures and the H2S analyzer is temperature stabilized to 50°C (122°F). Therefore, it is highly recommended to use heat-traced sample transport lines set at approximately 50°C.

3 Paul Stockwell IMA Limited, Peter Molyneux, Advantica Limited, An Investigation Into On-Line Hydrogen Sulfide Analysis, NEN & ISO/TC 158 GAS2009, World Trade Centre, Rotterdam, the Netherlands, February 2009. Also contact O’Brien Analytical http://www.obcorp.com/ for more information

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Figure 4: EP 316L tube with self-regulating AC-powered heat-trace tape, insulation and a 2-inch diameter outer jacket (left). Also shown is a heat-shrinkable boot (right) used to attach the 2-inch bundle to an enclosure and allow the tube to pass through the enclosure wall.

Sample Conditioning

In the context of this paper, the sample conditioning system is on an enclosed panel near the analyzer. The purpose of the sample conditioning system is to filter particulates and liquid (if present), control the final pressure and flow to the spectrometer (the TDLAS cell), and to provide a bypass stream to sweep the liquid separator(s). The system will include a relief valve for safety purposes which is typically set at 50 psig. All of the effluent is eventually passed out through the vent. Additionally, the sample system provides a way to validate the analyzer with a gas standard. All of this equipment is provided by the analyzer manufacturer in a heated enclosure which is set to 50°C. The considerations for installation of the H2S sample conditioning system are:

- The inlet flow is 4-5 slpm (8.5-10.6 SCFH) and the inlet pressure is 25-45 psig

- The standard vent pressure range is 800-1200mbara and is intended for vent to atmosphere. This range accounts for most conditions that the analyzer may be exposed to. However, alternative ranges can be specified.

- Optionally, the analyzer and sample conditioning system can be set up for vent-to-flare. This option will allow for a higher vent pressure (up to 1700 mbar) and a check valve will be included to prevent backflow during flare pressure spikes. This option must be specified at the time of order.

- Optionally, the analyzer can be set up with a validation port with an automated (or manually actuated) validation trigger that can be set up to record validations on a timed basis or on-demand. See “validation” section below.

- It is good practice to use a baffle on the atmospheric vent especially if high winds are expected to prevent sudden pressure spikes on the vent

There are certain applications, especially in production and gathering sites as well as gas conditioning applications where excessive amounts of water, glycol, amine, etc may be present. For example, if liquids or aerosols are present under normal or abnormal conditions, it may be necessary to install special hardware upstream of the analyzer. For example, a liquid knock-out, a coalescing filter, a chiller, or other means may be prescribed by the analyzer manufacturer. For this reason, it is essential that the particulars of the stream and the installation as well as any potential liquid carryover be communicated to the factory for design consideration.

Safety

For gas streams containing H2S, extreme care must be taken to prevent personal exposure. It is recommended for H2S levels above 300 ppmv that enclosed sample conditioning systems have the following protective hardware:

- Sample System Purge: Additional port allows users to purge sample system prior to maintenance

- Cabinet Purge: Additional port and vent on the enclosure allows user to purge cabinet if needed

- Sensor Port: Additional port allows user to insert an H2S sensor probe to check for H2S levels inside

- Warning Labels advising operators of the danger. For example “WARNING, High concentration of H2S may be present inside enclosure. Connect H2S test probe to test port to confirm no H2S is present prior to opening door. Purge if required”

Validation

Periodic validation assures the user that the analyzer is working properly. There are two methods that can be used to validate the TDLAS H2S analyzer using accurate “Cal-Gas” standards. A gas standard with 5 ppmv balance methane is a typical blend to be used on pipeline transportation applications for a rapid and simple

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precision test. In some cases, nitrogen background can be used and other concentrations may be required depending on the applications and the measurement range. Gas standards can also be used to validate speed of response, repeatability, and to verify the analyzer’s tolerance to other components in the stream matrix. The procedures for these tests are not covered in this paper; however they can be requested from the analyzer manufacturer.

Figure 5: Two potential setups for validating the H2S analyzer. If manual validation (left) is utilized, it is convenient to install a 3-way valve in the line for validation at the time of analyzer commissioning.

Conclusion

It is well understood by industry that an extractive analytical measurement system is comprised of two things; an analyzer and a sample conditioning system. It is the goal of this document to provide the necessary information for pipeline companies to continue its quest for best sample system design practices.

Summary of important considerations covered in this paper:

- Design sample extraction, sample transport and specify sample conditioning according to the principles outlined in this document

- Understand flow rates, phase envelopes, pipeline pressure, temperature, dewpoint temperatures, ambient temperatures, before designing sample systems

- Use membrane-tipped probe and chose pressure regulation while preventing condensation while taking Joule-Thomson cooling

- Maintain 18-30°F buffer between gas temperatures and dew point temperatures at all pressures

- Read ASTM D5503 and API 14.1

- Use only “analytically correct” sample conditioning components

- Consider the sample transport tubing internally wetted surface treatment and heat trace requirements to achieve the best speed of response and measurement accuracy

- Be careful to vent the analyzer properly according to the specifications of the analyzer (atmospheric versus vent-to-flare)

- Communicate all aspects of the application to the analyzer manufacturer that may help determine the best options. Describe the application in which the analyzer is to be used; ie production, gathering, sweetening (amine versus liquid or solid scavenger, etc) biogas, downstream of compressor, glycol contactors, pipeline transportation or distribution, and so on.

- Consider the necessary safety hardware when dealing with high H2S concentrations (purge ports, warnings, etc)

- Set up the analyzer validation system during analyzer commissioning

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SAMPLING WET NATURAL GAS FOR BTU AND MOISTURE ANALYSIS

Shannon Bromley, A+ Corporation, LLC

Introduction

Current industry standards, by virtue of their scope, do not address the sampling of “wet” natural gas. There is no

consensus on a clear definition of the term “wet” natural gas. For the purpose of this paper, “wet” natural gas is

defined as a natural gas stream containing liquid of any type. Wet gas is sometimes referred to as “multi-phase”

flow.

It is a well known fact in the industry that the largest source of sample distortion in natural gas sampling stems from the sample system. Sampling clean, dry natural gas, which is well above its dew point temperature, is a relatively simple task. Sampling natural gas that is near or below its dew point temperature is not so simple. For this reason the industry is now focusing on proper methods for sampling wet natural gas. This document will present an overview of the problems involved with sampling wet natural gas for on-line BTU and moisture analysis, give guidance on designing sample systems tailored for wet gas sampling, and provide updates on where the industry is on research and standards involving wet natural gas sampling.

Defining the problems

Wet gas is more prevalent in pipelines today, than ever before, due to the rapid expansion of interconnecting pipelines and unfavorable natural gas/NGL product price. Previously, the gas in a pipeline would come from a small number of known producers. Today, the gas flowing through the pipeline could have come from many varied sources including: deepwater offshore platforms (rich, high hydrocarbon dew point gas), natural gas storage facilities (potentially high moisture concentration), traditional gas plant producers (de-hydration, CO2, H2S, and N2 control as well as removal of condensates), coal bed methane producers (98% methane), low cost producers (de-hydration only) or global exporters of LNG. Unfavorable natural gas/NGL product price has resulted in producers leaving the higher energy value, heavier components in the transport gas instead of stripping the heavier components out of the gas to produce condensates.

While leaving the heavier components in the gas gives a greater return to the producers, these components become an issue to the transporters and end users of the gas when they start to condense and “drop out” of the

gas phase as the temperature of the gas drops below the hydrocarbon dew point. From an operations standpoint, hydrocarbon liquids in the gas stream can lead to increased costs and operational problems (hydrate formation, issues with pressure regulator stations in which the large temperature drop due to the vaporization of the liquid components results in freezing of the valves, and damage to end user equipment such as turbines). Because of the operational risks involved when hydrocarbon liquids are present in the gas stream, transporters are beginning to mandate limits of the hydrocarbon dew point to their suppliers. If the hydrocarbon dew point requirement is not met by the supplier, the transporter may reject the gas stream. From a measurement standpoint, hydrocarbon liquid carry over into the sample system can result in an inaccurate compositional analysis, directly affecting the heating value (BTU) assessment, and can also cause damage to the analyzer.

The water vapor concentration (moisture) in the natural gas mixture is also of significant importance to the transporters from both a measurement and operations standpoint. From an operations standpoint, high levels of water in the pipeline can lead to corrosion and hydrate formation. From a measurement standpoint, the presence of water in the natural gas stream will affect the heating value (BTU) per unit volume of gas. The more water present in the natural gas stream, the less valuable it is because the water displaces some of the hydrocarbon components in the natural gas mixture thus reducing the heating value and monetary value per unit volume of gas. Contracts and tariffs usually limit the amount of water vapor content allowed at the custody transfer point.

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From the previous discussion, it can be seen that the need to ACCURATELY determine both the BTU value and moisture content of the gas are extremely important from both a measurement and operations standpoint. Since the largest source of analytical error in sampling can be attributed to the sample system, any initial upfront investment made towards ensuring that the sample system has been properly designed is time and money well spent.

Industry Standards

As previously stated, current industry standards (by virtue of their scope) do not address the sampling of wet natural gas streams; however, the last revisions of GPA 2166 and API 14.1 industry standards give some very good guidelines on sampling wet natural gas streams. In regards to sampling wet natural gas (multi-phase) streams, Appendix B.3 of the API 14.1 standard states, “…When sampling a multi-phase liquid-gas flow, the recommended procedure is to eliminate the liquid from the sample. The liquid product that flows through the line should be determined by another method…” Current sampling technology is not sufficiently advanced to obtain a sample representing both phases.

The API 14.1 standard does not state the conditions for which the liquid should be eliminated; however, these conditions can be found in the GPA 2166 standard. The GPA 2166 standard, General Note 3 of Section 2.1.3 states, “…Any component of the sampling system that separates unwanted liquids from the sample stream must

be operated at flowing line temperature and pressure.” Appendix B, Section 2.1 states that an insertion membrane filter probe meets the requirements for proper liquid removal.

After reviewing these two standards, it becomes evident that a representative natural gas sample is one that represents the vapor phase composition of the natural gas source flowing in the pipeline. If the source gas is “wet”, the liquid portion must be removed at pipeline conditions of pressure and temperature.

Natural Gas Phase Diagrams

A phase diagram is a graph which shows the gas/liquid phase relationships at various pressure and temperature conditions and is a very useful tool when designing and/or troubleshooting natural gas sample systems. The reader must be able to interpret a natural gas phase diagram in order to follow along with the examples given in this paper. The phase diagram of Figure 1 is of a typical natural gas composition in the 1250 BTU range, and the Soave-Redlich-Kwong equation of state was used to calculate the diagram. The parts of the phase diagram in Figure 1 are referenced below:

1. The critical point (B) is the pressure and temperature conditions where a phase boundary ceases to exist.

2. The cricondenbar (C) is the highest pressure point on the phase envelope.

3. The cricondentherm (D) is the highest temperature point on the phase envelope.

4. Line A-B is the section of the phase diagram known as the bubble point curve.

5. Line D-E is the section of the phase diagram known as the dew point curve.

6. Line C-D is usually referred to as the retrograde dew point curve.

7. The area to the left of the phase envelope and below the critical point is the liquid phase.

8. The area to the right of the phase envelope and below the critical point is the gas phase.

9. The area underneath the phase envelope is the “multi-phase” region.

10. The area above and to the right of the critical point is the “supercritical fluid”. This fluid lacks properties that define it as a gas or a liquid. It is sometimes referred to as “dense gas”.

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Figure1- Natural Gas Phase Diagram

Dew Points

When the amount of water or hydrocarbons in a natural gas mixture reaches its saturation point, the water or hydrocarbons are said to be at their dew point. Typically, the water dew point is different from the hydrocarbon dew point. The water dew point is the pressure and temperature combination at which water in the mixture will begin to change phase (from vapor to liquid or vice versa), while the hydrocarbon dew point is the pressure and temperature combination at which hydrocarbons in the mixture will begin to change phase. Figure 2 illustrates the difference in the dew points. In this figure, created by E. Bowles and D. George of Southwest Research Institute, the hydrocarbon dew point line is shown for a particular natural gas mixture, as are the water dew point lines for two different water concentration levels, 7 and 80 lbm/MMSCF.

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Figure 2 – Example of Hydrocarbon and Water Dew Points for a Natural Gas Mixture (E. Bowles and D.

George, 2010)

Since both the moisture dew point and the hydrocarbon dew point are of concern in a natural gas mixture, the one having the highest dew point temperature (at operating pressure) should be referenced for decisions concerning heating and pressure regulation requirements.

Heating Requirements

In order to prevent the heavier hydrocarbons from condensing in the sample system, the API 14.1 standard makes the following recommendation in Section 6.6 “Due to the uncertainty in measuring or calculating the

hydrocarbon dew point, it is recommended that the gas being sampled be maintained at least 30°F (17°C) above the expected hydrocarbon dew point throughout the sampling system.” This means that all of the components in

the sample system (probes, pressure regulators, tubing, filters, sample cylinders, etc) should be maintained at least 30°F (17°C) above the expected hydrocarbon dew point.

To the author’s knowledge, the only reference the API 14.1 standard makes to moisture dew point is from ASTM

D 1142, Standard Test Method for Water Vapor Content of Gaseous Fuels by Measurement of Dew-Point

Temperature, which recommends that the sample should be 3°F (1.7°C) above the dew point. It then refers the reader to the recommendations contained in section 6.6, which are discussed in the above paragraph.

Extracting the sample

The first task of a sample conditioning system is to extract a REPESENTATIVE natural gas sample. As previously discussed, a representative sample is the gas phase as it exists in the pipeline. Recall that there currently are no methods to accurately sample both the gas and liquid phases, which is why the standards evade the subject. To remain in compliance with industry standards and to maintain the integrity of the sample, the liquid portion of the sample should be excluded under flowing line pressure and temperature conditions. This is best accomplished by using a sample probe having a phase separation membrane integrated in the probe entrance, thus excluding liquid “inside” of the pipeline (see figure 3).

Heating the sample or reducing the pressure BEFORE liquid is removed will distort the gas phase composition and render the sample unrepresentative. If the liquid separation process is carried out external to the pipeline, care should be taken to maintain the pressure and temperature of the source gas from its extraction point and throughout the liquid separation process. While it may be relatively simple to maintain source pressure external to the pipeline, it is not practical to maintain the source temperature as it may require heating the sample system in the winter and cooling the sample system in the summer.

Phase Diagram for 7- and 80-lbm H2O/MMSCF NaturalGas

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Figure 3- Probe with Phase Separation Membrane Tip

Pressure Regulation

After the sample has been properly extracted, the challenge becomes preventing condensation of the sample during pressure reduction. In order to achieve this task, enough heat must be applied at, or prior to, the point of pressure reduction to offset the Joule-Thomson cooling effect (approximately 7°F per 100 PSI of pressure reduction). Regulating probes are designed to offset or prevent excessive Joule-Thomson cooling during pressure reduction. This is accomplished by having the pressure reduction valve located in a section of the sample probe which is inside of the pipeline, thus allowing the sample gas to be “heat sinked” to the source gas for the purpose of offsetting some of the Joule-Thomson cooling effect. When sampling a wet gas, the regulating probe should have a phase separation membrane tip (see Figure 4) to reject liquid BEFORE pressure reduction takes place. If the liquid is not removed before pressure reduction, it can affect the performance of the probe regulator and distort the sample composition.

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Figure 4- Pressure regulating probe with membrane tip

It is important to note that although some heat from the flowing gas source will be transferred to the sample gas when an insertion probe regulator is used to reduce the pressure, the heat transfer process is not 100% effective. The actual temperature of the sample gas during the pressure reduction will be somewhere between an isothermal (without temperature change) and adiabatic (no heat transfer) temperature condition. Experience has shown the “practical” temperature point to be near the midpoint of the adiabatic and isothermal temperature points. Figure 5 illustrates the “practical” temperature. The source gas temperature and pressure conditions are represented by point (A). Point (C) represents the sample gas temperature after an adiabatic pressure drop. Point (B) represents the sample gas temperature after an isothermal (without temperature change) pressure reduction. Point (D) represents the actual (practical) temperature of the sample gas after a pressure reduction with a typical insertion regulator.

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Figure 5- Defining the Practical Temperature

When trying to determine the appropriate type of pressure regulator, a phase diagram for the stream to be sampled should be used as a reference, as well as the “practical” temperature calculation of the sample gas

during pressure regulation.

Figure 6 shows the phase diagram for a 1300 BTU gas with source conditions of 600 PSIG and 50°F. The source conditions are located within the 2 phase region of the phase diagram, indicating that the source gas is “wet”.

Figure 6-1300 BTU “wet” gas @ 600 PSIG & 50°F

Use of a phase separation membrane tip probe will exclude the liquids present in the source gas. A new phase diagram should be plotted using only the gas phase composition to determine pressure regulation requirements. Figure 7 depicts the phase diagram for the gas phase composition of the “wet” gas composition shown in Figure 6. It can be seen that the source gas, without the entrained liquid, is now on the phase boundary (saturated and at its hydrocarbon dew point). The line extending between the points labeled “source” and “outlet” indicates the “practical temperature” condition of the sample gas during pressure regulation with a membrane tip insertion

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regulator. Note that the practical temperature line does not keep the sample 30°F above the hydrocarbon dew point at all times. Recall that this recommendation by industry standards was due to the uncertainty of the dew point measurement. In this case, there is no doubt b/c the gas phase is at its dew point. Since the “practical”

temperature line does not traverse the phase envelope, the sample should remain in the gas phase during the pressure reduction and an insertion pressure regulator can be used to reduce the pressure of the gas in this example.

.

Figure 7- Gas phase composition @ 600 PSIG & 50°F with practical temperature calculation for an

insertion pressure regulator

If the operating pressure and temperature conditions for the “wet” gas stream depicted in Figure 6 were to change, the gas phase composition would change and pressure regulation requirements should be re-evaluated. Suppose the operating conditions are now 1000 PSI and 50°F, as shown in Figure 8.

Figure 8- 1300 BTU “wet” gas @ 1000 PSIG & 50°F

Use of a phase separation membrane tip probe will exclude the liquids present in the source gas. A new phase diagram should be plotted using only the gas phase composition to determine pressure regulation requirements. Figure 9 depicts the gas phase composition for the “wet” gas at the operating conditions shown in Figure 8. The

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line extending between the points labeled “source’ and “outlet” indicate the “practical” temperature of the sample

gas during the pressure reduction. It can be seen that any pressure reduction without heating will cause the sample to traverse the phase envelope resulting in severe sample distortion and also impacting the performance of the regulator. This condition causes surging in single stage pressure regulators and can sometimes cause the regulator to “freeze up” as a result of the large temperature drop associated with the vaporization of the liquid

components.

Figure 9- Gas phase composition @ 1000 PSIG & 50°F with practical temperature calculation for an

insertion pressure regulator

The author’s recommendation is to extract the sample using a membrane tip probe so liquid is rejected under

flowing line pressure and temperature conditions. Next, transfer the sample to an external regulator through a sample line heated at least 30°F above the cricondentherm temperature (make sure all components from the outlet of the probe leading into the regulator are heated). The regulator should be a multi-stage regulator with reheating of the sample gas between stages to prevent condensation from occurring during pressure regulation and to maintain the sample 30°F above the cricondentherm temperature during the pressure reduction. Figure 10 shows the practical temperature condition for a particular multi-stage regulator, having pre and post heat capability between each stage of pressure regulation, maintained at 100°F. It can be seen that the “practical”

temperature of the gas is maintained 30°F above the cricondentherm temperature throughout the pressure regulation process.

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Figure 10- Gas phase composition with practical temperature calculation for a multi-stage, heated

pressure regulator- Source conditions of 1000 PSIG and 50°F

Transporting the sample to the analyzer

When possible, the distance between the sample take off point and the analyzer should be minimized. The dew point temperature of the sample at reduced pressure should be calculated or measured. If the ambient temperature at any time can drop to within 30°F of the dew point of the sample gas, then heat tracing is required. The entire sample conditioning system, from the probe/pipeline wall intersection up to the gas chromatograph inject valve/ moisture analyzer sensor must be maintained above the dew point temperature, otherwise condensation will occur which will distort the sample composition and may damage the analyzer.

Analyzer Protection

Even though filtration of the sample to remove solids and liquid contaminants may be performed at the sample point, it is still important to provide a secondary means of filtration as close as possible to the analyzer/sensor. When pipe and tube fittings are “made up”, small bits of metal can be released into the flowing sample gas stream and cause damage chromatograph and sample system valves. Liquid can be present due to condensation of heavy hydrocarbons in the event of an upstream failure or loss of heat tracing. Coalescing filters and phase separation membrane based separators with a liquid blocking device can be used for filtration purposes close to the analyzer/sensor.

Summary

Designing a sample system for a “wet” natural gas source requires careful attention and a basic knowledge of thermodynamics. Knowing the dew point temperature of the gas to be sampled is a must. As previously stated, since both the moisture dew point and the hydrocarbon dew point are of concern in a natural gas mixture, the one having the highest dew point temperature (at operating pressure) should be referenced for decisions concerning heating and pressure regulation requirements.

A membrane tip probe is always recommended to remove entrained liquid under flowing line temperature and pressure conditions in accordance with industry standards. Use of equations of state and hardware selection software programs are recommended to generate the phase diagram of the stream to be sampled and simulate the “practical” temperature conditions of the sample during pressure reduction to assist in regulator selection. It is also important to calculate the dew point of the sample after pressure regulation to determine if the sample will need to be heated as it is transported to the analyzer.

References

American Petroleum Institute. Manual of Petroleum Measurement Standards. Chapter 14- Natural Gas Fluids Measurement, Section 1- Collecting and Handling of Natural Gas Samples for Custody Transfer. American Petroleum Institute, Washington, D.C., February 2006.

Bowles, Jr., Edgar B. and George, Darin L. Heat Quantity Calculation Relating to Water Vapor in Natural Gas. Proceedings of the 85th International School of Hydrocarbon Measurement. Tulsa, OK, 2010.

Bromley, Shannon M. and Mayeaux, Donald P. Considerations for Sampling Wet, High Pressure, and Supercritical Natural Gas. Proceedings of the 85th International School of Hydrocarbon Measurement. Tulsa, OK, 2010.

Gas Processor’s Association Standard 2166-05. Obtaining Natural Gas Samples for Analysis by Gas Chromatography. Gas Processor’s Association, Tulsa, OK, 2005.

Massey, Brad. Sample Conditioning and Contaminant Removal for Water Vapor Content Determination in Natural Gas. Proceedings of the 83rd International School of Hydrocarbon Measurement. Tulsa, OK, 2008.

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SAMPLING AND CONDITIONING DURING LOADING, UNLOADING, AND STORAGE OF LNG

James N. Witte, El Paso Corporation

Introduction

For LNG terminal operators sampling of LNG has proven to be a challenging task to get right. This paper will discuss some of these challenges and approaches to resolving LNG sampling problems from the perspective of the operator’s point of view.

The ISO 8943 Standard

The applicable standard for LNG sampling is ISO 8943. ISO 8943 is a document which provides standard guidance toward the construction of an LNG sampling system, and provides examples of three sample system designs for continuous or intermittent sampling.

The standard describes probe requirements, vaporizer requirements, compressor requirements (when required), the gas sample holder (accumulator), gas sample compressor (when required), and the use of constant pressure or constant volume sample cylinders.

Guidance is provided toward keeping the sample line length at a minimum. This is an important requirement because heat from ambient sources is sufficient to vaporize the LNG product. The risk of premature vaporization of the sample is increased by the heat exchange surface area of the sample tubing.

The standard also describes methods for taking spot samples during a cargo transfer event.

The requirements in the standard also describe sampling during steady flow conditions on the pipeline and maintaining steady flow in the sample system.

Practical Experience

This discussion is intended to relate some of my personal experience and lessons learned in working with LNG sampling. Usually, a sample system is designed and installed by the engineering and design company doing the construction of an import or export terminal. Their charge is to construct in accordance with applicable standards and they will usually do so using their best reasoned knowledge of the subject. It is usually the case, however, that they do not have first hand operating experience with LNG sampling.

In practice, the operator first realizes that there is a concern when the chromatographic analysis of the LNG indicates an unstable compositional analysis between consecutive analyses. It is not unusual for the indicated ethane mole percent to vary by whole percentages in consecutive analyses.

The operator may wonder if the cargo is not well mixed or perhaps they are experiencing cavitating flow in the transfer piping. Both of these scenarios are highly unlikely and the operator should evaluate the sample system for potential errors.

The Sample System

A review of the sample system begins at the pipeline tap. The sample should be taken through a sample probe inserted in the radial position of 90 or 270 degrees around the pipe diameter. The probe must be long enough to avoid pipe wall turbulence. The sample tap must also be installed in a straight length of pipe to avoid cavitating flow conditions that might be caused by piping elements such as elbows or bends.

The connecting tubing is usually ¼ inch stainless steel tubing which must be well insulated. Vacuum jacketed tubing is considered the state of the art for insulation purposes. The purpose of good insulation is to deliver a liquid LNG flow stream without prematurely flashing the liquid product. If the product does begin to flash in the sample tubing this can cause the sample to not be representative of the fully mixed liquid in the pipe.

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The vaporizer must be designed to provide a sufficient level of heat for the design flow rate to totally vaporize the LNG sample stream. Passing liquid LNG through the vaporizer will contaminate the downstream gas accumulator which will once again produce a sample analysis result that is not representative of the liquid stream in the pipeline.

Flow through the system must be controlled on a mass flow basis, such that the vaporizer heat rate is adequate to produce a uniform flash. Unsteady flows can and will produce undesirable results.

In LNG terminals there is always a flow through the plant piping which includes the load lines. Operating pressure on the pipes is a function of whether a cargo transfer is in process or not. There is usually at least a two times increase in line pressure when cargoes are transferred versus the normal plant circulation flow rate. Such step changes in piping pressures have been noted to create challenges for operator tuning of sample flow rates. It may be useful to install a restriction at the inlet of the sample tubing to avoid significant changes in flow rate through the sample system.

The sample system discharge is also a significant consideration. Many times the sample discharge is routed into a vapor return line. This vapor return line, however, can change pressure significantly during cargo transfer and may produce back pressure which could affect the ability of the sample mass flow rate controller to be effective in regulating a constant flow rate.

Another challenge to steady state flow maintenance is the practice of spot sampling by operators at specific times during a cargo transfer. Proper sizing of the gas accumulator bottle should include an allowance for the volume of gas that might be taken during the spot sampling events. Since the samples are taken at low pressure conditions, the constant volume sample cylinders tend to be quite large. Perhaps a better idea is to use constant pressure cylinders that have been pre-charged with helium at a pressure of twice the line pressure. The operator can then sample by filling the bottle very slowly instead of the quick large volume fill.

Checking the Results

Even when all indications look to be normal it is a good idea to test the sampling results by comparing with a load port analysis. The fuel usage is accounted for in the ship records and on the custody transfer reports. Knowing the amount of boil off LNG used during the voyage allows the operator to calculate a set of theoretical gas properties by backing out the fuel usage as methane equivalent and re-normalizing the cargo molar analysis from load port. The desirable outcome is agreement within one Btu per standard cubic foot.

An alternative is to evaluate send out composition and determine the cargo impact on plant inventory. This methodology is more challenging and requires consideration of plant tank boil off measurement and is impacted by other measurement uncertainties within the plant.

Conclusion

Proper LNG sampling is challenging even when the system is correctly designed. Operators must be observant of variable results which can indicate the problems previously described. Knowledge of the sampling standard does not adequately prepare the operator to handle the challenges of this type of operation. Even if the operator is experienced in natural gas sampling they are likely to find the learning curve for LNG sampling to be a steep learning curve.

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BENEFITS OF TRAINING COMPANY PERSONNEL IN THE SCIENCE OF SAMPLE CONDITIONING AND ANALYSIS

Brad Massey, Southern Star Central Gas Pipeline

Introduction

Sample conditioning and analytical processes have become greater focal points within the natural gas industry in recent years. This has led to more research and technological advances relating to these areas within our industry. Understanding the science of these technologies continues to be challenging among a vast majority of natural gas companies. Each sector, production, processing, transmission and end users, have specific analytical and sample conditioning challenges that must be dealt with. Our industry faces ongoing challenges of educating not only incumbent personnel but also a growing number of those newly hired. Conducting the proper level of training to personnel in the design, installation and utilization of sample conditioning and analytical methods will be critical in assuring that the potential problems associated with sample conditioning and analysis can be avoided. This paper will discuss the benefits of conveying reasoning, knowledge and recommended practices of sample conditioning and analytical procedures to all individual involved in the design, installation, operations and maintenance of this equipment.

Technology Advancements

Sample conditioning and analytical practices have evolved tremendously over the past couple of decades. For example; as late as the 1980’s many companies utilized calorimeters to report heating value and typically coupled this with either online or portable gravitometers to report relative density. Many of these installations didn’t use a probe and often times used steel pipe as sample transport lines. Large carbon steel containers were utilized to collect a large volume of gas to take to a calorimeter in order to run a BTU analysis. Where the sample was taken and how it was collected was given little consideration as long as you got the gas from the pipe into the cylinder. None of these methods are acceptable in today’s practices as the accuracy of results and reliability of the information obtained from a complete compositional analysis is critical in determining information for operations and billing purposes. The need for real time information has become critical to the operations and nominations processes of natural gas companies. The criticality of properly designed, installed and operated sample conditioning and analytical systems for on-site analysis and collecting a sample in a cylinder for analysis by a laboratory have advanced to rely on understanding and implementing scientific principles.

Today, a good number of natural gas companies have adopted some level of awareness for the need of sample conditioning and recognized the need to update their analytical devices. Even so this doesn’t necessarily mean that the level of educating their personnel has met the needed emphasis.

Analytical devices have undergone technological advancements in detectors and cells that have improved response, accuracy and reliability. Improved electronics, faster processors, increased memory and programming methods have improved making the systems more reliable with the ability to store, display and communicate results timely and accurately.

As technology advances so does the need for education. The importance of providing this education is true throughout the organization to insure that the right amount of emphasis will be placed where needed and resources made available to insure that proper training occurs.

Training of Company Personnel

Natural Gas Companies must understand the importance of properly designed, installed, operated and maintained sampling and analytical equipment. Without insuring that all of the criteria are met for each of these areas the sampling and analytical systems are likely to provide improper results. A well supported and balanced education effort in each of the aforementioned areas become essential to obtaining effective and reliable sampling and analytical systems.

Education and Training of Design Engineers

It is unlikely that engineers have received the level of training for the proper design of sampling and analytical systems throughout their formal education. It should be recognized that engineers assigned to design these systems should receive the necessary education from industry sponsored forums and schools. Involvement in

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industry standards groups responsible for development of reports and standards relating to the proper sampling and analytical design and operational practices will provide an understanding of the recommendations contained within those documents.

The designer must understand the fundamentals of the sample conditioning system and the analytical device for which the sample is being collected. For example if attention isn’t given to the importance of sample probe length then the result may be that the sample is not taken well away from the pipe wall and will be susceptible to accumulating liquids and debris traveling on the wall of the pipe. On the other hand if the probe is too long it may be subjected to vibration from gas velocities leading to a failure related to metal fatigue. Consideration must also be given to where and how much pressure reduction to take within the system. Designing pressure reductions within the system without accounting for temperature loss will likely distort the sample especially if operating near dew point temperatures. Several other factors must be considered, such as avoidance of multiphase sampling, filtration and liquid removal methods and the use of supplemental heat, are well documented in several industry publications and standards.

There are numerous types of analytical equipment some of which include gas chromatographs, O2, water vapor, CO2, total sulfur and H2S analyzers. Each of these analytical processes has multiple methods for detecting the targeted component or components. Regardless of the type of analysis being performed and method utilized, an understanding of how to design the sample conditioning system to deliver a representative sample is critical to avoid improper results.

Beyond the sample conditioning system there is also a need to understand the analytical device operating fundamentals. How to determine sample frequency, proper ventilation, power requirements and maintenance requirements are just a few considerations. Each of these factors should be understood prior to designing analytical systems.

Performance and the long term maintenance of the devices may be negatively impacted if systems are not designed.

Education and Training of Project Engineers and Installers

Regardless of the system design it is imperative that the actual installation must be accomplished with an understanding of the design purpose. This will insure that those directing the installer or the installer don’t deviate from the planned system design.

Each part of the sample conditioning system must be installed properly and in the correct sequence to insure the design purpose is met. For example; what if the end of a section of heat trace tubing is not properly sealed and is exposed to moisture that wicks into the insulation and damages the electric heat trace. Using the heat trace is to avoid phase changes in the sample and operating without it may result in condensation of either water vapor or hydrocarbon liquids in the sample tubing. This damage may go unnoticed providing a non-representative sample for an extended period of time and result in an expensive repair or replacement. Another example might be that in an area limited for space. In this case a liquid removal component might be re-oriented, re-positioned or simply left out. This would provide a potential for liquids to enter the sample stream and distort the sample resulting in poor sample results.

Project engineers and installers should receive training from manufacturers and industry schools to insure they understand the principles of sample conditioning systems and analytical devices. Also, they should get some guidance from the design engineer on the proper installation and purpose of the system components. Performance and the long term maintenance of the devices may be negatively impacted if equipment is not properly installed.

Education and Training of Field Personnel

Historically a good number of natural gas companies have accomplished much of their technical training requirements with “On the Job Training” methods. If an internal formal training program exists or is created within an organization, keeping it current with new technological developments, industry standards’ updates and current industry practices becomes a costly and demanding maintenance effort. The effort and investment in providing the proper level of training is relatively insignificant considering the negative impact of improperly trained field personnel.

Due to the complexities surrounding gas sampling, sample conditioning and analytical methods a great deal of re-enforcement to support the correct methods must exist within each organization’s measurement group. Without a commitment to provide sustained meaningful training in this area, many technicians and other field personnel will

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not utilize the correct sampling practices or provide the proper maintenance to sample conditioning equipment. Also they will have difficulty in properly operating and maintaining analytical devices. Personnel become frustrated with trying to operate and maintain equipment for which they haven’t received the proper level of training. Typically this lack of training leads to quick fixes, an unawareness of problems or simply ignoring symptoms because they don’t know how to take corrective action.

Problems Associated with Improperly Trained Technicians

Improperly extracting a natural gas sample into a cylinder for off-site analysis or into a sample transport system to an on-site analyzer has a high potential of delivering a non-representative sample. Some of the problems associated with this follow:

Maintaining Safety o Correct procedures for installing probes need to be in place and taught to prevent accidental

dislodging of the probe from the pipe. o Properly installing and maintaining regulators and relief devices to prevent overpressure of the

equipment should be a priority. o Sampling H2S and understanding the danger of exposure is required.

Insuring that basic sample conditioning principles are understood to provide conditions for the best opportunity to extract a representative sample to be delivered to the analytical device.

o Use of a probe. o Probe insertion depth. o Pressure reduction.

Where to cut the pressure How much to cut at a given point How to protect from an overpressure situation.

o Utilizing the correct filtration methods for the desired analytical process o Length and diameter of sample transport tubing. o Supplemental heat of the sample. o Protection from environmental conditions. o Sources of contamination o Measures required to protect from contamination. o Understanding how contaminants affect different analytical methods.

Operating and Maintaining Analytical Equipment o Monitoring the analyzer for proper performance per company’s O&M procedures and

manufacturers recommendations o Updating response factors on gas chromatographs o Care and maintenance of calibration gases. o Supplying the proper carrier gas from a reputable supplier o Configuration of the correct sampling frequency for each stream o Utilizing Auto Calibration o Monitoring and Correcting Alarms o Collecting and Transmitting data o Filtration Maintenance o Pressure Control Operation and Maintenance o Cleaning and maintaining detectors and cells o Maintaining power systems and uninterruptible power systems (UPS’s)

Summary

Technology advancements, related to analytical and sample conditioning, are often recognized in industry standards and technical papers but the importance of training field personnel to understand these same principles is often overlooked. Providing adequate training that conveys a purpose for design, installation, operation and maintenance of equipment company personnel will respond appropriately. Without the knowledge and skills individuals will typically resort to the most convenient and quickest way to get results without regard to how the end result is impacted. Educating employees in the design, installation, operation and maintenance of equipment and processes used in sample conditioning and analytical systems is essential in providing results that are both reliable and accurate.

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ARE COMPANY SAMPLING PROCEDURES IN LINE WITH CURRENT STANDARDS?

Matt Holmes, ONEOK, Inc.

Involvement in measurement standard review and development varies from organization to organization in the natural gas industry, even though any changes to a measurement standard can affect all industry organizations relatively equally. Changes to measurement standards can affect organizational operating procedures in the field as well as in the main office. Not keeping up with the latest versions of measurement standards can create liability for an organization, as well as preventing them from encountering information that could reduce their lost and unaccounted for gas, ultimately affecting their bottom line.

Organizational Involvement in Standards Development

Management philosophy is one of two primary drivers of an organization’s involvement in measurement (and other) standards development. These philosophies can be broken down into six main categories:

Be involved to get it the way we want it. Be involved to stay informed of impending changes. Be involved to have a company presence in the industry. Don’t be involved, we’ll deal with it during ballot. Don’t be involved, we’ll do what the industry says. Don’t be involved, we don’t care what it says.

Be involved to get it the way we want it. This philosophy is seen in many organizations that were the primary drivers of recent changes to measurement standards, and typically comprise the main portion of volunteers that make up the workforce utilized by the standards organizations. The philosophy is that by participating in the development of standards, an organization can prevent any changes that could cause significant costs or changes to its desired mode of operation. Some organizations may even take this to the point of trying to change the standards in a manner that would directly increase their revenue, but most often participation is just to prevent any undesirable or erroneous changes.

Be involved to stay informed of impending changes. This philosophy is also found in many organizations within the industry. The philosophy is that participating in standard development is the best way for an organization to stay abreast of any impending changes and the overall direction of the industry. These organizations participate for informational purposes instead of having an agenda as to what they would like to see changed.

Be involved to have a company presence in the industry. This philosophy, though probably not admitted by many top managers, is the final philosophy for participation in standards development, and is generally hidden behind one of the previous two. The philosophy resembles a marketing technique, that an organization’s presence at industry functions will maintain or increase its perception by the industry, and as such possibly increase market share or revenue through indirect means. Standards workgroup meetings and operations conferences are seen as networking opportunities.

Don’t be involved, we’ll deal with it during ballot. This philosophy is another one seen commonly in the industry. The philosophy is that participating in standard development is not necessary because an organization can get their opinion and necessary changes in during the balloting process, which takes place before any standard is published. These organizations will typically not have representatives in the workgroups or at the operations conferences, but will submit a ballot with comments on content that they would like to see changed.

Don’t be involved, we’ll do what the industry says. This philosophy is commonly seen in smaller companies, many of whom can’t devote the resources (manpower and memberships) to standard development. The philosophy is that the working group that is working on the standard has sufficient scientific knowledge and the interest of the industry in mind, so erroneous or negative changes are unlikely to occur.

Don’t be involved, we don’t care what it says. While this philosophy is not a common one among manner top managers, it is still found here and there throughout the industry. Fortunately, at least one of the other management philosophies tends to override this one. The philosophy is that the organization is capable of determining its own best practices and procedures without any input from the rest of the industry. This typically comes from managers who are only concerned with the bottom line, and not the means to which it is improved.

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Many of these philosophies can be found spread out within a single organization. Which philosophy is utilized by the organization is dependent on the number of supporters and their influence with top management, and can change as an organization’s management experiences turnover.

The second of the two primary drivers of an organization’s participation in the development of measurement standards is budgetary concerns. Participation in standards development can become expensive, so management’s perception of its return on investment will drive how much an organization will participate.

One cost to participate in standards development comes in the form of memberships, which many of the industry organizations publishing standards require for an organization to participate. Such memberships generally require a fee that is based on the amount of oil or natural gas the organization transports in a given timeframe. With many organizations publishing standards that affect the natural gas industry, such as the Gas Processors Association, American Petroleum Institute, and the American Gas Association, it can quickly become expensive for an organization to maintain memberships to all of them.

Another cost to participate in standards development is the travel costs associated with workgroup meetings and conferences, including hotels, airfare, rental cars or taxi fares, and meals. Each industry organization typically holds one or two conferences a year, where updates are given on the progress of various standards, and workgroups meet to work on standards that are under review. The locations for these conferences vary from year to year, and can even be held outside of the continental United States, meaning employees wanting to participate will need to have an up to date passport. Also, with many organizations publishing standards that overlap or cover independent areas, the travel costs for an organization to participate in standards development can add up quickly.

Yet another cost to participate in standards development is the time associated with the travel, workgroup meetings, and independent review. Organizations that want to ensure they are up to date with the standards or are able to influence the direction of the standards must employ competent individuals to do so. While these individuals generally perform other duties for their organization, they must also devote a significant amount of time to review standards independently and work with others from different organizations to make changes and corrections as needed. Again, with many organizations publishing standards that overlap or cover independent areas, the amount of time necessary to keep up with all of them becomes quite significant.

Thus, between membership dues, travel costs, and devoting personnel to the task, organizations invest a significant amount in the review and development of measurement standards.

Why Stay Involved

With all of the costs associated with keeping up with standards development, and the potential struggles with management perspectives regarding such involvement, it can be easy to allow participation in standards development and standard review to slide, if it even remains an item on the measurement department’s goals list. However, despite the costs it is important that organizations stay informed of changes to standards that potentially impact their business processes, both in the office and in the field. Generally, the corporate measurement department will take on the responsibility of staying informed of these changes and as such take on the responsibility of applying the standards to the organization and communicating them to all that they impact.

The reasons for maintaining awareness of the changes to standards that impact an organization’s business process are relatively simple: it is generally seen as a good business practice to perform the same processes and procedures as peer companies, and it can give insight into the direction the industry is headed, such as utilizing new technology or standardizing on training practices.

Maintaining awareness of standards will allow an organization to implement the same practices that the rest of the industry utilizes in a timely manner, which is a generally good business practice. Such implementation can also be used defensively in the case of litigation. Using the same practices as the rest of the industry has proven to be defensible practices. Also, such awareness and implementation helps prevent significant government involvement of the oil and natural gas industry’s measurement practices.

Measurement standards also allow an organization to maintain awareness of new developments and directions the industry is heading. These developments can be in in regards to the latest technology that is generally accepted by the industry, as in the case of ultrasonic and Coriolis measurement, or how the industry feels it should be handling specific problems such as measurement technician training, as seen in a recent AGA white paper. Although the AGA white paper on measurement technician training is not by definition a standard,

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maintaining awareness of measurement standards would lead to the discovery of such items, providing beneficial supplementary information in addition to that provided in the standards themselves.

Application and Communication

The reasons to apply the information and practices from standards to an organization are also relatively simple, and in some cases overlapping with the reasons to maintain awareness. The first reason to apply the information in the standards is liability. As mentioned previously, applying the practices that the rest of the industry is utilizing has been proven to be a defensible practice in the case of litigation. Although it is possible to prove practices that deviate from the standards as technically sound, it can be costly to do so and such a defense is less likely to be successful.

The second reason an organization would benefit from applying measurement standards is to keep its business. Since the standards are generally accepted industry-wide, interconnecting companies are going to expect standards to be utilized both in the field and in the office. This is typically going to be seen in any interconnect agreement between companies, and will also be included as the basis for any audits that may be conducted from time to time.

Finally, measurement standards tend to be scientifically based. As such, applying them will help an organization more accurately determine the volume and energy at each measurement point, which in turn will help determine lost and unaccounted for volumes and energies. Since these values are typically associated with an organization’s overall performance or even the bottom line, getting them right is essential.

Communicating the changes in the standards and how they affect an organization is also important. An organization can only benefit from knowledge that it utilizes, so those that maintain awareness of the standards must also communicate the changes to those that are affected so that they can be implemented properly. Also, failure to communicate the changes throughout an organization can lead to liability.

Since the responsibility of maintaining awareness of the changes in standards generally falls to the central measurement department, the responsibility of communicating that information throughout the organization also falls to the central measurement department. This can generally be accomplished through the use of memos, training roundtables or conferences, or internal measurement policies, procedures and guidelines. Standards changes should be communicated to all that may be directly or indirectly affected by them, including measurement technicians, operators, field supervisors, and office personnel.

If this information remains solely in the hands of those responsible for maintaining awareness, the organization will not be able to benefit from any of the changes and may also be held liable for failing to implement them. If the information is poorly communicated throughout an organization such that it only reaches a fraction of the operating groups responsible to carry out the changes an organization may also be held liable for not implementing the changes equally throughout. This can be even harder to defend in the case of litigation, making it look as though the organization was preferentially deciding when to implement standards changes and when not to. Thus, it is critical that standards changes be effectively and thoroughly communicated throughout the entire organization.

Ways to Stay Involved

The best way to stay involved in standards organizations and to remain aware of standards development is to be directly involved in the standards development process. However, due to the budgetary constraints or management perspectives listed previously, this may not always be possible. Fortunately, there are other ways to stay informed of standards development and industry trends.

One such way to stay involved and informed is through attendance at industry schools. These opportunities, such as the International School of Hydrocarbon Measurement (ISHM) and the American School of Gas Measurement Technology (ASGMT), are generally well attended by office personnel, measurement technicians, and subject matter experts. Attending these events will allow an individual to learn both in a classroom-type setting and through conversation with others in the industry who are actively involved in standards development.

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Another way to stay informed and involved is through attending regional or local measurement training events, such as Coastal Flow Measurement’s lunch and learn seminars or Midwest Measurement Society’s Standards Roundtable. Attending these types of events also allows an individual to learn from others who are actively involved in the standards.

Finally, one can also stay involved and informed through networking with business contacts. By attending some of the events listed above, an individual can develop a network of business contacts that can provide information regarding changes in standards and standards development. These individuals can also help condense or synthesize the information regarding the changes, potentially reducing the time it takes to remain informed.

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IMPACT OF INCORRECT ANALYSIS ON COMPANY PROFITS

Don Sextro, Targa Resources

Introduction

The value of natural gas is often based on its energy quantity which is determined from the volume of gas delivered and its heating value or it is based on the volume of gas delivered combined with other results from the gas analysis. Compositional analysis of the natural gas is used in the calculation of the volume delivered, in the heating value of the gas itself and in the related physical properties of the gas. There are numerous sources for sampling and for analysis error, but it is safe to assume that sample conditioning can be the largest source of error in the analysis reported for a natural gas stream. At the end of the day, sampling errors impact company profits.

Profit is the surplus remaining after total costs are deducted from total revenue. This means that profit is sensitive to both the revenue side of the equation as well as the cost or expense side. When expenses exceed revenue, the profit is negative and is instead known as loss. Unprofitable operations usually don’t last long.

Incorrect sampling and/or analysis activities cause errors that can be significant and these errors can translate into monetary, workload and legal problems. Using an incorrect analysis can have a financial impact in several ways, one through the affect on total energy and/or allocated products delivered, second by the affect on the company’s work processes and reputation and third, usually after not achieving desired outcome by discussion and negotiation, through legal action. An error in total energy or allocated products delivered will cause a direct, quantifiable change to the cost or the revenue side of the profit equation. The cost of rework, of addressing audit questions, of negotiating changes and of applying a correction through to the final billing or payment is a real cost although it may be difficult to accurately quantify. Reputation is a valuable asset to a company. The change in the perception of a company’s reputation due to an error is hard to measure in dollars, but it is real. Lastly, if legal action occurs, some of the costs then become quite clear but other costs, such as costs for the time involved in attending to the details of the litigation, are less clear although probably large.

There are two general ways that a natural gas analysis can be in error. The first exists when the sample is not representative of the gas flowing through the meter. The second occurs when the process of analyzing the sample and calculating the results goes astray.

Errors Caused by Unrepresentative Sampling

It is important to understand that the analysis needs to represent the natural gas that actually flowed through the meter both in composition and in time. This means that the small quantity of natural gas captured in the sample cylinder and the even smaller quantity injected into the laboratory chromatograph, the portable chromatograph or injected periodically into the online chromatograph from the flowing stream needs to be the same composition as the gas flowing through the delivery meter at that point.

Improper sampling techniques or faulty sampling systems can distort the sample extracted from the source piping to have a different composition than the gas flowing through the meter. The distortion can cause the sample to be lighter than the source, meaning that the sample contains more methane than the source, but it can also distort the sample and skew the composition toward the heavier components. A sample skewed toward the lighter components will occur when the sampling technique or equipment extracts some of the heavier components. An example would be when a sample is chilled below its hydrocarbon dew point such that a portion of the heavier components never make it into the sample container. One way a sample can be skewed toward the heavier, higher carbon number, components is by picking up a portion of liquid previously condensed in a low spot in the sample tubing.

Besides the need for the gas sample to have the same composition, the timing of the analysis of that sample also needs to match the time of the flowing stream. For example, a composite sample collected throughout the month should be applied to the volume measured over that same month. Likewise, the sample sent to an online chromatograph should arrive at the chromatograph at nearly the same time as the gas flows through the meter and then be analyzed and the results applied.

Once a sample becomes unrepresentative, the analysis is no longer meaningful for the gas that flowed through the meter. The best chromatograph, technician and methods can’t compensate for the unrepresentative sample.

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Errors Caused in Sample Analysis and Results

The diligence of sample system design and installation and then capturing a representative sample can be squandered if the laboratory, portable or online chromatograph distorts the sample in its injection process, uses an analysis method that is not appropriate for the sample or incorrectly calculates the results.

Distortion would result if the sample was not properly heated before or during the sample injection such that part of the sample condenses and is not analyzed. By extension, the next sample analyzed may pick up that condensed liquid and be distorted as well. Any leakage from the sample cylinder or introduction of components not present in the sample will distort the original sample. Remember that the sample originally captured should consist of gas molecules in the same proportion as the gas flowing through the meter at the time of sampling and then the portion of the sample injected into the chromatograph should have this same proportion of gas molecules.

A failure in using the appropriate analysis method or a failure in the chromatograph hardware will likely cause an error in the analysis. For example, if the natural gas sample contained helium but the chromatograph used helium as the carrier gas, then the resulting analysis would be unable to detect the helium content. This will overstate the concentration of the components that the chromatograph detects by the amount of helium undetected.

The analysis report depends on a properly calibrated chromatograph and proper calibration is tied directly to the standard blend. An error in the standard blend causes errors in the analysis reported from the chromatograph. Since the analysis report includes several calculated results such as heating value (heat content or BTU factor), relative density (specific gravity) and GPM content, incorrect physical properties will affect these calculated results.

Financial Impact on the Value of Natural Gas Delivered

In the most straightforward example, the heating value determined from an incorrect analysis and applied to the volume of natural gas delivered has a proportionate and direct affect on the value of the gas that flowed through the delivery point. Where the natural gas stream is valued by the energy delivered through the meter, an error in heating value of 1 BTU per standard cubic foot for a quantity of 20 million cubic feet per day of natural gas causes a financial change of $84 per day when natural gas is priced at $4.20 per dekatherm. Financial change means that for the two parties buying and selling gas across this meter, one party gains and the other party loses. This difference is equivalent to $2,600 per month and $30,700 per year if the error in heating value continued for that period.

The equation that represents the financial impact of a heating value error when applied to the volume of natural gas delivered for some time period is:

So for the example, the equation for the financial impact of the heating error per day becomes:

A larger heating value error, volume or price will result in a larger financial impact and the converse is true as well. This error has a direct affect either on costs for the purchaser or on revenues for the seller.

Financial Impact on the Value of Theoretical Components

Some natural gas, such as unprocessed gas gathered from wellhead delivery points, is valued in part by the quantity of components that theoretically would condense from the gas into liquid. The common term in the U.S. is GPM which is an abbreviation for gallons (G) of a specific component per (P) thousand (M) cubic feet of natural gas. This is often a step in a gas plant settlement process.

As an example, assume that the sample composition is skewed toward the heavier hydrocarbon components because some heavier components partially condensed during the previous sampling activity and were picked up in the next gas sample before it was analyzed in the chromatograph. The composition and GPM results for the original, incorrect analysis and for the revised, correct analysis follow in Table 1. Using the revised analysis as the correct result, the overall change in GPM content for the components from ethane through hexanes and heavier is a decrease of 3.4%. Notice the effect of the erroneous sample skewing the composition toward the

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lighter components in that the ethane gallons theoretically available actually increased while the remaining components decreased.

Original Analysis Revised Analysis

Component Mole % GPM Mole % GPM CO2 Carbon Dioxide 1.133 1.133 N2 Nitrogen 0.413 0.413 C1 Methane 80.753 81.203 C2 Ethane 10.983 2.930 11.083 2.957 C3 Propane 3.815 1.049 3.715 1.021 IC4 Isobutane 0.638 0.208 0.588 0.192 NC4 Normal butane 1.088 0.342 0.988 0.311 IC5 Isopentane 0.347 0.127 0.247 0.090 NC5 Normal pentane 0.348 0.126 0.248 0.090 C6+ Hexanes and heavier 0.482 0.210 0.382 0.166

Total 100.000 4.992 100.000 4.827

Table 1

The quantity of each component that would theoretically condense from a quantity of gas is determined by multiplying the volume of gas in units of thousands of standard cubic feet by the individual component GPM. Assuming 10 million standard cubic feet of gas flowed through the meter associated with this sample, the result is then determined through multiplying 10,000 MCF by the component GPM values in Table 1 to arrive at the original, revised and the change in gallons as shown in Table 2.

GPM values are not typically calculated or used for carbon dioxide, nitrogen or methane because these components are not extracted as liquid products in the typical gas processing plant.

Theoretical Gallons

Component Original Revised Change CO2 Carbon Dioxide N2 Nitrogen C1 Methane C2 Ethane 29,304 29,568 264 C3 Propane 10,486 10,210 -276 IC4 Isobutane 2,083 1,920 -163 NC4 Normal butane 3,422 3,107 -315 IC5 Isopentane 1,266 901 -365 NC5 Normal pentane 1,259 897 -362 C6+ Hexanes and heavier 2,098 1,663 -436 Total 49,918 48,266 -1,653

Table 2

An example of the financial change caused by the incorrect analysis is calculated by multiplying for each component the change in gallons by the price per gallon as shown in Table 3. Isopentane and heavier components are typically priced as natural gasoline because that is their usual destination as a finished product. This example shows a decrease in the value of the theoretically condensable liquids of $2,816. The time frame is not given in this example, but it could be applicable to a production month for a moderate flow rate well or could be applicable to a day if it was a high flow rate well. The composition could have been skewed toward the lighter

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components due to sample distortion from sampling through a system below hydrocarbon dew point temperature which would reverse the direction of the dollar value of the change.

Theoretical Gallons

Component Gallons $ / Gal Value C2 Ethane 264 $ 0.48 $ 127 C3 Propane -276 $ 1.07 $ (295) IC4 Isobutane -163 $ 1.40 $ (229) NC4 Normal butane -315 $ 1.37 $ (431) IC5 Isopentane -365 $ 1.71 $ (624) NC5 Normal pentane -362 $ 1.71 $ (619) C6+ Hexanes and heavier -436 $ 1.71 $ (745) Total -1,653 $(2,816)

Table 3

Because this is a simplified example that ignores contract terms, the actual affect on the dollars exchanged between two parties for this volume of gas will likely be different. However, the example is useful to illustrate the direct financial change caused by an inaccurate sample.

Integration / Entry Error

It is useful to illustrate the analysis result when a component is missed such as could occur if the chromatograph integrator misses a peak or if a manually input result was skipped. In this case, the assumption is that the next calculation step normalizes the identified component concentrations. If an analysis incorrectly assigns the isobutane composition as zero and normalizes the remaining components, the affect on the analysis report would be as shown in Table 4.

Missing iC4 Correct

Mol% GPM Mol% GPM

Nitrogen 1.174 1.155 Methane 61.158 60.163

Carbon Dioxide 0.546 0.537 Ethane 15.665 4.120 15.410 4.054

Propane 13.103 3.550 12.890 3.493 Isobutane 0.000 0.000 1.628 0.524

Normal butane 4.211 1.306 4.142 1.284 Isopentane 1.091 0.392 1.073 0.386

Normal pentane 1.212 0.432 1.192 0.425 Hexane 1.840 0.790 1.810 0.777

100.000 10.590 100.000 10.943

Heating value, sat, base 1,526.82

1,554.51 Relative density, real, sat 0.9221

0.9398

Table 4

By omitting the isobutane concentration, the heating value, relative density and total ethane plus GPM are originally understated. This outcome could be predicted since a hydrocarbon component was removed thus causing the inert components, as well as the remaining hydrocarbons, to increase in the re-normalization process.

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Affect on Gas Volume

The volume of gas flowing through a meter is determined, in part, based on its density. An analysis error can translate into an error in the volume flowing through the meter. For an orifice meter, one form of the flow equation uses the real gas relative density Gr as an input to determine the volumetric flow rate Qv. If the real gas relative density from an incorrect analysis is used to calculate the volume flowing through an orifice meter, the change in volume can be predicted through a straight-forward calculation. Assuming all variables besides Gr remain constant, the ratio of the volume for the correct analysis QvA to the ratio of the volume resulting from the use of the incorrect analysis QvB can be shown as:

ffrB

wsf

vFTd

ffrA

wsf

vFTd

vB

vA

TZG

hZPdYEC

TZG

hZPdYEC

Q

Q

1

12

1)(

1

12

1)(

61.7709

61.7709

Which, because all variables besides Gr are assumed to remain constant, reduces first to:

rA

rB

rB

rA

vB

vA

G

G

G

G

Q

Q

1

1

So, the square root of the ratio of the incorrect relative density (B) to the correct relative density (A) is multiplied by the original, incorrect volume QvB to predict the correct volume QvA.

rA

rBvBvA

G

GQQ

For the analysis example shown in Table 4, the correct volume is 0.96% lower than originally calculated 1,500 MCF but the associated energy content increases when using the correct analysis by 0.84% and the ethane and heavier GPM total increases by 3.23%. See the details in Table 5 below. Note that the assumption at the beginning of this discussion is that all variables besides the real gas relative density are constant, but in fact the compressibility at flowing conditions, Zf1, is a function of composition. The change in volume is likely less sensitive to the flowing compressibility, but it is important to quantify this change in the process of calculating the volume associated with the correct analysis. The typical approach is to apply the correct analysis in the measurement system and recalculate the volume.

Missing iC4 Correct Change

Volume, MCFd 1,500 1,486 -0.96% Energy, Dth 2,290 2,310 0.84% C2+ GPM 10.59 10.943 3.23%

Table 5

Financial Impact from Rework

In addition to the difference in the value of the energy delivered through a meter and the difference in theoretical liquid quantities associated with the gas flow through the meter, there are costs associated with correcting a bad sample or an incorrect analysis.

ffr

wsf

vFTdvTZG

hZPdYECQ

1

12

1)(61.7709

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When a bad sample is identified or suspected, the first cost is for the time and equipment required to capture a new sample. This includes the cost for the individual to travel to the meter site and to collect a sample of the gas. There are cases where the meter is an hour or more away from the technician’s office, so a significant part of the day is used to do something a second time because of a failure the first time. Particular care is often taken at this point to avoid sampling problems if that was the original cause of the error. There are labor costs and vehicle costs onshore and labor and transportation costs offshore. Offshore transportation costs can be substantial, especially when a helicopter trip is required.

The newly collected sample may have to be transported to the laboratory, often as a special case. It seems that bad samples have a way of showing up during the closing process which puts a particular sense of urgency behind the delivery of the sample to the lab. There can be instances, such as inclement weather offshore, when it is not possible to capture a new sample in the time available before a deadline. The sample also has to be analyzed at the lab and there is a cost for that effort.

A less visible cost is the opportunity cost of repeating the sampling and analysis work. The additional sample collection, transportation, handling and analysis takes a person away from the work they were planning or expecting to accomplish and has them do it again. Rework is expensive and disruptive.

The analysis report can be thought of as the conclusion of the sampling and analysis process, but the analysis report is an input to volume calculation and financial settlement calculations. The composition and relative density are used to determine flowing density and compressibility as part of the volume calculation which is then combined with heating value for the energy transferred through the meter. Financial settlements rely on the analysis for heating value and for theoretical hydrocarbon liquid content. If the error is discovered later in the work process, after volumes have been calculated with the erroneous information, or even further in the process, after accounting and settlement calculations have been made, the cost of correcting the error increases because the rework touches more people and processes.

When an error is identified at an even later time, such as an error found during an audit, the cost to rectify the problem again increases. Usually it is more difficult and takes longer to gather facts from what is now considered history and to evaluate the presence of and affect of an error. More people are involved and the direct costs of their efforts and the opportunity cost of rework are evident. In the event that the error results in legal action, costs again rise because additional people are involved and often these individuals charge higher rates.

Conclusion

A correct analysis results from analyzing a sample that represents the flowing stream in both composition and time, was determined using the proper analytical method applied to the right equipment identifying all pertinent components and was calculated accurately and with correct physical properties. However, the best laboratory equipment and procedures cannot produce the correct analysis from a sample that is not representative of the flowing stream because it was distorted through improper sampling techniques.

There are financial implications when an analysis result is in error because the valuation of the natural gas passing through a meter changes and because of the costs for rework and to investigate and resolve errors. The valuation depends on the type of financial settlement pertinent to the meter as discussed in several examples in this paper.

The impact of an incorrect analysis on the profitability of a company is directly related to the volume of natural gas measured and associated with an erroneous analysis and the magnitude of the analysis error. Thoroughly evaluate errors to find the root cause so that they can be eliminated. Avoid rework and its cost which is a drain on profitability. The lowest cost and hence most profitable approach is to properly sample and analyze the natural gas so that the resulting volume, energy and associated valuation is correct the first time and every time.

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