Hydrocarbon Processing | MAY 201361 Special Report Maintenance and Reliability A. GLAUN and J. SHAHDA, GE Oil & Gas, Avon, Massachusetts Prevent methane hydrate formation in natural gas valves Gas flow across a control valve is considered a classic “throttling” process that is defined by energy not being add- ed or extracted from the process gas as it traverses the valve. Therefore, total enthalpy is preserved, entropy increases and the process is thermodynamically irreversible. The consequences of this process are that many real gases experience a drop in temperature while following the constant enthalpy line as the pressure drops across the valve. This effect was first described by William Thomson and James Joule, and it now bears their names. The Joule- Thomson effect is leveraged in the production of cryogenic fluids such as liquid oxygen, nitrogen and argon, and it is the principle of operation behind most air conditioners and re- frigeration in use today. Natural gas production, storage and transmission usually take place close to ambient conditions, where a small change in temperature can induce the formation of methane clath- rates (hydrates). Once formed, methane hydrates can block valves, fittings and pipelines. Newer facilities are using higher transmission pressures, causing the temperature inside the valve to approach or drop below 0°C, with the risk of icing on the outside of the valve. The discussion here focuses on the thermodynamics in- volved and on the requirements for a successful natural gas valve application in which the incidences of hydrate formation and icing of the valve are reduced. Computational fluid dy- namics (CFD) studies are also presented showing the Joule- Thomson effect in a real-world valve application. What are methane hydrates? Natural gas/methane hy- drates (also known as methane ice) are crystalline water ice- like particles, where methane molecules are trapped inside hy- drogen-bonded water molecules. Under the right conditions of pressure and temperature, these form semi-solid particles that tend to agglomerate, building up inside pipelines, valves and other process equipment. Why worry about methane hydrates in valves? Hydrate ice particles may clog flow passages in control valves and, in particular, valves with noise attenuation trim (small drilled- hole cages, labyrinth passage stacks, etc.). This sometimes causes a major reduction in the flow across the valve, badly af- fecting system operation. Severe hydrate formation may even clog large passages of the valve body and pipeline. How do methane hydrates form? Hydrates form in natu- ral gas pipelines when the local fluid temperature drops below the hydrate-formation temperature at a specific pressure. This temperature drop can occur when the natural gas flows through a control valve, or when gas travels through transmission pipe- lines under cold ambient conditions or through any other piece of process equipment where the flow is restricted or accelerated in such an orifice plate. This phenomenon of temperature drop with pressure drop in a real gas is known as the Joule-Thomson effect. Note: Hydrates can form at temperatures well above the freezing point of water (FIG. 1). Hydrate-formation temperature is difficult to predict and is the subject of many academic papers. Prediction depends on temperature and pressure, water concentration and the compo- sition of the natural gas, where small concentrations of heavy hy- drocarbons and other gases such as O 2 , N 2 , H 2 S and CO 2 can af- fect the formation temperature. Software programs are available to help the user predict the formation temperature, but the only way to know for certain is to test a sample of the gas in question. How is the gas temperature drop calculated? Flow across a control valve is considered a throttling, constant enthalpy (is- 175 0 5 10 15 20 25 30 35 40 200 225 250 Temperature, K Methane clathrate, stable Pressure, MPa 275 300 325 FIG. 1. Stability curve showing that methane hydrate is stable at 0.1 MPa (1 bar) if temperatures are low enough, and that it is stable far above the melting point of ice (H 2 O) if pressures are high enough. Data courtesy of Lawrence Livermore National Laboratory.
Transcript
Hydrocarbon Processing | MAY 2013�61
Special Report Maintenance and Reliability A. GLAUN and J. SHAHDA, GE Oil & Gas,
Avon, Massachusetts
Prevent methane hydrate formation in natural gas valves
Gas flow across a control valve is considered a classic “throttling” process that is defined by energy not being add-ed or extracted from the process gas as it traverses the valve. Therefore, total enthalpy is preserved, entropy increases and the process is thermodynamically irreversible.
The consequences of this process are that many real gases experience a drop in temperature while following the constant enthalpy line as the pressure drops across the valve. This effect was first described by William Thomson and James Joule, and it now bears their names. The Joule-Thomson effect is leveraged in the production of cryogenic fluids such as liquid oxygen, nitrogen and argon, and it is the principle of operation behind most air conditioners and re-frigeration in use today.
Natural gas production, storage and transmission usually take place close to ambient conditions, where a small change in temperature can induce the formation of methane clath-rates (hydrates). Once formed, methane hydrates can block valves, fittings and pipelines. Newer facilities are using higher transmission pressures, causing the temperature inside the valve to approach or drop below 0°C, with the risk of icing on the outside of the valve.
The discussion here focuses on the thermodynamics in-volved and on the requirements for a successful natural gas valve application in which the incidences of hydrate formation and icing of the valve are reduced. Computational fluid dy-namics (CFD) studies are also presented showing the Joule-Thomson effect in a real-world valve application.
What are methane hydrates? Natural gas/methane hy-drates (also known as methane ice) are crystalline water ice-like particles, where methane molecules are trapped inside hy-drogen-bonded water molecules. Under the right conditions of pressure and temperature, these form semi-solid particles that tend to agglomerate, building up inside pipelines, valves and other process equipment.
Why worry about methane hydrates in valves? Hydrate ice particles may clog flow passages in control valves and, in particular, valves with noise attenuation trim (small drilled-hole cages, labyrinth passage stacks, etc.). This sometimes causes a major reduction in the flow across the valve, badly af-fecting system operation. Severe hydrate formation may even clog large passages of the valve body and pipeline.
How do methane hydrates form? Hydrates form in natu-ral gas pipelines when the local fluid temperature drops below the hydrate-formation temperature at a specific pressure. This temperature drop can occur when the natural gas flows through a control valve, or when gas travels through transmission pipe-lines under cold ambient conditions or through any other piece of process equipment where the flow is restricted or accelerated in such an orifice plate. This phenomenon of temperature drop with pressure drop in a real gas is known as the Joule-Thomson effect. Note: Hydrates can form at temperatures well above the freezing point of water (FIG. 1).
Hydrate-formation temperature is difficult to predict and is the subject of many academic papers. Prediction depends on temperature and pressure, water concentration and the compo-sition of the natural gas, where small concentrations of heavy hy-drocarbons and other gases such as O2 , N2 , H2 S and CO2 can af-fect the formation temperature. Software programs are available to help the user predict the formation temperature, but the only way to know for certain is to test a sample of the gas in question.
How is the gas temperature drop calculated? Flow across a control valve is considered a throttling, constant enthalpy (is-
1750
5
10
15
20
25
30
35
40
200 225 250Temperature, K
Methane clathrate, stable
Pres
sure,
MPa
275 300 325
FIG. 1. Stability curve showing that methane hydrate is stable at 0.1 MPa (1 bar) if temperatures are low enough, and that it is stable far above the melting point of ice (H2O) if pressures are high enough. Data courtesy of Lawrence Livermore National Laboratory.
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enthalpic) process. This implies that the process occurs over a very short period, making it adiabatic (no heat is lost or gained during the process); enthalpy is preserved, and the process is ir-reversible (i.e., entropy increases and cannot be recovered).
For a real gas flowing through a control valve, this process gives a lower downstream temperature. Additional lowering of the downstream temperature may occur due to high down-stream velocity of the expanded gas (Eq. 1). For natural gas and reasonable downstream velocities of less than 0.3 Mach num-ber (Ma), the velocity terms in Eq. 1 are two orders of magni-tude smaller than the enthalpy and can usually be ignored.
(1) h1 + V1
2
2= h2 + V2
2
2 Where:
h = Specifc enthalpyV = Fluid velocity1, 2 = Upstream and downstream conditions, respectively. Two common methods exist to calculate the temperature
drop of natural gas for a given pressure drop across the valve. The first method is to determine the enthalpy at the inlet pres-
sure and temperature and then to determine the outlet tem-perature at the same enthalpy and outlet pressure. Software programs and web-based calculators can give this data, but the Mollier chart for methane can also be used, assuming an isen-thalpic process in the valve from Eq. 1.
A Mollier chart, at minimum, displays properties of pres-sure, temperature, enthalpy and entropy on one diagram, allow-ing the user to define a state using only two properties and read-ing off the other properties (FIGS. 2–4). By definition, this is an accurate method of determining the downstream temperature; it is only limited by the accuracy of the Mollier chart and by the user’s ability to graphically interpolate the chart. Using soft-ware may be more precise, but the authors believe that a Mollier chart gives the user a visual sense of how the values are chang-ing and leads to a better understanding of the thermodynamics.
After determining the inlet condition on the chart, the user follows the lines of constant enthalpy until the downstream pressure line is reached. The temperature now can be read at this new position. The caveats to this method are that the as-sumption of constant enthalpy is just that—an assumption. In reality, there is some heat transfer across the valve/pipe bound-ary, and the process is never precisely a true throttling process. These “inefficiencies” will result in lower temperatures than the ideal determined above.
The second method is a general rule used in the natural gas industry where, for every 100-psi pressure drop, there is a cor-responding 7°F temperature drop; however, this rule is limited to a maximum valve inlet pressure of 1,000 psi. Using the Mol-lier chart for methane at room temperature, the accuracy of this rule can be evaluated. It varies from 5.5°F/100 psi for in-let pressures of approximately 300 psi, to 6°F/100 psi for inlet pressures of approximately 1,000 psi.
The rule takes into account inefficiencies and is somewhat conservative. However, for high inlet pressures and small pres-sure drops, the rule is very conservative. For example, from a
2703.5 3.7 3.9
Entropy, kJ/kg
Methane throttling process
4.1 4.3 4.5
280 A
1
2B
290
300
310
Constant enthalpyConstant pressu
re, bar
Hydrate formation line
Tem
pera
ture,
K 320
330
340
350200 160 140 120
80
90
100
FIG. 2. Temperature drop inside a single-stage trim valve (Line A) and a multi-stage trim valve (Line B).
drop of 1,000 psi to 800 psi, the temperature drop is 4.5°F/100 psi per the Mollier chart.
The temperature downstream of the valve is a concern, but the lowest temperature inside the valve trim must also be calculated. In fact, the pressure and temperature at the trim vena contracta (smallest area of flow in the trim) are usually lower than the pressure and tempera-ture downstream of the valve. The lower temperatures inside the valve are due to sudden accelerations of the gas inside the valve trim and typically are thermody-namically isentropic (reversible) in nature.
These internal pressure drops can be very large for single-orifice valves and less so for multi-stage control valve trims that drop the pressure over a number of controlled pressure-drop stages; they can be visual-ized if the reader follows the constant entropy line on the Mollier chart. Fortunately, this vena contracta low tempera-ture is not a permanent change of state, and the temperature due to this effect recovers after the gas passes through the valve trim, leaving only the vena contracta and adjacent areas cold.
How can hydrate formation be avoided? There are several solutions to reduce the incidence of hydrate formation in valves:
1. Appropriate inlet temperature. The natural gas inlet temperature can be chosen so that, when the pressure drops across the valve, the resulting downstream temperature of the natural gas is always above the hydrate-formation temperature. Gas temperatures are normally determined by the gas field, so external heating of the inlet gas prior to entering the valve may be the only option. This is, however, expensive in terms of heating equipment and fuel costs. The required inlet tempera-ture can be determined using the Mollier chart or the 7°F/100 psi rule, by starting at a known safe outlet temperature and then working backward.
2. Inhibitor injection. Inhibitors can be injected upstream of the control valve to prevent the gas from reaching the hydrate-formation temperature, thereby preventing the formation of hy-drates. The most common inhibitors are methanol and ethylene glycol; these typically can be recovered from the gas and recir-culated. However, inhibitor injection and recovery can be costly.
3. Valve trim design. As noted earlier, even if the valve outlet is above the hydrate-formation temperature, the inter-nal valve trim temperature may not be, and hydrate formation is possible within the valve. If this is the case, then selecting a multi-stage valve that gradually lowers the pressure across the valve trim will help the situation. Note: Trim selection can-not prevent downstream hydrate formation if the downstream temperature is below the hydrate-formation temperature. The Joule-Thomson effect is a “state” condition from upstream to downstream, and changing the valve trim will not affect this.
The red lines in FIG. 2 show the properties of methane as the fluid travels through the control valve from upstream (1) to downstream (2). The long, dashed red line labeled “A” repre-sents a single-stage control valve where the temperature drops below the hydrate-formation line (blue line), making it pos-sible for hydrates to form inside the trim. The dotted red line labeled “B” represents a multi-stage control valve where the temperature does not drop below the hydrate-formation line, thus preventing hydrates from forming inside the trim.
Valve icing. Under high pressure-drop conditions, the outlet temperature in the valve may fall below the freezing point of water. This may not cause hydrate formation inside the valve
because inhibitors such as monoethylene glycol (MEG) can be used with gas at −10°C. Even so, condensation and freezing on the outside of the valve body and pipeline can have serious ef-fects. For example, coastal gas fields on the Saudi Arabian pen-insula are notoriously humid and prone to ice buildup.
Extremely thick layers of ice can build up, preventing access to the valve body or pipe wall. These layers of ice can add sig-nificant weight to the valve and pipeline, with the possibility of structural and/or vibration problems. The valve bonnet may become iced, thus seriously impacting the valve stem packing and raising the potential for leakage.
A real-world problem. A natural gas producer was flowing gas through a control valve with the following winter conditions:
• Upstream: 975 psia, at 57°F• Downstream: 180 psia, with icing on the valve and pipe.The icing was unacceptable to the plant operator, and the
only line heaters available were rated at 350 psia and could not be used to heat the inlet gas. For the purposes of this example, the natural gas is assumed to be methane.
An isenthalpic analysis showed that the downstream tempera-ture reaches 14°F (FIG. 5, points 1–2). Using a gas industry gen-eral rule, the downstream temperature could reach 1.3°F (FIG. 5, points 1–3). The end user required that the downstream temper-ature be no less than 40°F to prevent icing and hydrate formation.
FIG. 5. Heating required at inlet pressure to keep outlet temperature above 40°F.
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Solution 1: Heat gas at the valve inlet. A common solution to this type of icing problem is to use pipeline heaters just up-stream of the valve. The fuel for the heaters is usually the flow-ing natural gas itself. However, this solution is costly in terms of lost gas and the expense of high-pressure heaters.
Referring to FIG. 5 and using the 40°F minimum outlet tem-perature requirement (dashed blue line), point 4 can be located and the temperature can be back-calculated to maintain 40°F at the outlet of the valve. The gas inlet temperature should be above 95°F (point 6) to avoid falling below 40°F at the outlet.
Using an isenthalpic analysis, the inlet temperature should be above 84°F (point 5) to avoid falling below 40°F at the outlet. The difference between points 5 and 6 is quite substantial, and, as discussed earlier, the authors believe that, for high pressures, the 7°F/100-psi rule is overly conservative. The isenthalpic anal-ysis is ideal for this measurement; the true value lies somewhere in between.
Note: The addition of hydrate inhibitors might lower the end user’s specification of 40°F minimum temperature at the outlet of the valve. In this case, point 4 would move to a lower value to the left and the analysis would be repeated, thereby lowering the min-imum required inlet temperature to prevent hydrate formation.
The rate of energy input required to heat the gas can be read directly from FIG. 5 by subtracting the enthalpy at point 6 from the enthalpy at point 1. If this value is multiplied by the mass flowrate in kg/s, then the answer is the rate of energy input in kJ/s or kW.
As mentioned before, this analysis is independent of the type of trim in the valve. If the analysis shows that the tempera-ture at the outlet is low enough to form hydrates, then changing to a multi-turn or multi-stage trim will not alter the conditions at the outlet. A multi-stage valve will, however, limit very low temperatures inside the valve trim.
Solution 2: Use available low-pressure heaters. The first option considered was to save the customer from having to buy new equipment by using the existing, 350 psia-rated line heat-ers (FIG. 6). This method required staging the pressure drop by placing another valve in the line. The first pressure drop oc-curred from 975 psia to the heater maximum pressure of 350 psia, and then down to the outlet pressure of 180 psia.
In the methodology of this solution, the outlet drop should not fall below 40°F, which allows point 4 to be located. An is-
enthalpic analysis is used to back up to the heater pressure of 350 psia, which gives points 3 and 5, respectively. Point 2 is located on the 40°F minimum line, and an isenthalpic analysis is used to back up to the inlet pressure of 975 psia, giving points 1 and 6, respectively. The heat input is calculated from points 2–5. The addition of heat at 350°F reduces the minimum inlet temperature to 84°F from 95°F, with no heat addition.
Note: As with solution 1, the addition of hydrate inhibitors might lower the end user’s specification of 40°F minimum at the outlet of the valve. In this case, point 4 would move to a lower value and the analysis would be repeated, thereby low-ering the minimum required inlet temperature to prevent hy-drate formation.
Solution 3: Apply new low-pressure heaters. If the an-swers from the first two solutions are inadequate, the next step is to examine the lowest-pressure-rated line heaters that can be used and still operate year-round at the minimum inlet tem-perature of 57°F. This requires a slightly different methodology than that used previously.
Referring to FIG. 7 and starting at the minimum inlet tem-perature at point 1, the pressure must then be determined for when 40°F is reached. This gives point 6, which is at 732 psia. Knowing that the endpoint is point 4, one can work backwards, using isenthalpic analysis, to arrive at point 5. The enthalpy difference between points 5 and 6 is the resulting heat input required. Comparing the result of solution 3 to solution 1, a small reduction in heat input is required. Note that the heat in-put found when using the general rule is identical to that found when using the isenthalpic analysis.
At this point, it becomes a question for the end user of eco-nomics and complexity. Solution 1 appears to be less complex, since it requires only one control valve; however, a large pres-sure drop across one valve results in a severe service applica-tion with low internal valve trim temperatures, possibly requir-ing an expensive multi-turn or multi-stage valve. High-rated pressure-line heaters also must be purchased, and significant heat must be added to the upstream gas.
Solution 2 does not appear to be useful since an additional valve would need to be added to the line to accommodate the pressure drop from 350 psia to the outlet pressure of 180 psia, and the system would not be able to run unless the ambient
2
1 6
3
4
5
Constant temp.
Min. gastemp. 57°FInlet pressure
Outlet pressure
Heater max. pressure
40°F
20°F
60°F
80°F
100°F
0°F
0
200
400
600
800
1,000
1,200
770 790 810 830 850 870 890Enthalpy, kJ/kg
Pres
sure,
psi
Heat input 16 kJ/kg
FIG. 6. Minimum inlet temperature when using the existing low-pressure line heaters.
2
1
36
4
5Constant temp.
Min. gastemp. 57°FInlet pressure
732 psi
Outlet pressure
40°F
20°F
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80°F
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0
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1,200
770 790 810 830 850 870 890Enthalpy, kJ/kg
Pres
sure,
psi
Heat input, 56 kJ/kg
FIG. 7. Heat input at lowest line heater pressure for preventing hydrates at minimum inlet temperature.
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Maintenance and Reliability
(inlet) temperature reached 84°F. However, there are some geographical locations where this might not be such a burden.
Solution 3 requires the complexity of an additional valve, but the pressure drop is broken up into two reasonable steps, resulting in two less severe applications and warmer internal valve trim temperatures. Lower-rated pressure-line heaters would need to be purchased, and significant heat would need to be added to the upstream gas.
Numerical analysis for valve trim temperature. CFD can be used to model the flow through the trim of the valve. An accurate CFD analysis to capture Joule-Thomson effects is only possible if advanced real gas formulations are used. A real gas model takes into account non-ideal compressibility effects, whereas an ideal gas CFD analysis will only predict localized drops in temperature resulting from increases in ve-locity and reductions in local pressure due to the acceleration of the fluid as it negotiates turns in the valve trim.
The proprietary CFD program used in this case has a real gas model that uses the Redlich-Kwong formulation to pre-dict the fluid properties, taking into account the non-ideal compressibility of the working fluid. The program predicted 54°F at the outlet of the trim, which compares favorably to an isenthalpic analysis using a Mollier chart, which predicts 54.5°F.
FIG. 8 shows a representative 22-turn trim (pictured is a half-symmetry model of one flow channel) with an inlet
pressure of 975 psia and an outlet pressure of 180 psia. The results show the even, gradual, staged pressure drop through the valve trim. This style of trim serves two main purposes: One is to lower the outlet jet Ma, producing a quiet valve, and the other is to reduce the temperature drop inside the valve trim to minimize hydrate formation and icing.
FIG. 9 shows the temperature results. The plot clearly shows the Joule-Thomson effect of a permanent temperature drop from inlet to outlet. It also shows areas inside the valve trim
FIG. 8. CFD pressure plot of a representative 22-turn, multi-stage valve trim.
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Maintenance and Reliability
where the temperature can drop below the outlet temperature, although areas are localized and the temperature recovers.
Even accepted global standards for valve sizing, such as IEC 60534-2-1, do not take this real gas effect into account and base the sizing exclusively on upstream temperature, assuming an ideal gas where interstage and downstream temperature equals the upstream temperature. (Note: IEC 60534-2-1 does warn that compressibility of real gases should be taken into account if an accurate upstream density is to be calculated.)
IEC control valve noise prediction standard 60543-8-3 explicitly states in its scope statement that ideal gas laws are assumed, and it uses the upstream temperature to determine downstream density, velocity and Ma. For this specific prob-lem, the downstream velocity can be under-predicted by 8%.
Takeaway. Hydrate formation and icing in natural gas pipe-lines and valves can be greatly reduced or even prevented en-tirely if a detailed study of the thermodynamics of the system is undertaken. An intimate knowledge of the process gas is es-sential so that properties, such as hydrate-formation tempera-ture, can be accurately determined. Also, using real gas analysis, internal valve trim temperatures can be calculated, leading to a better understanding of the type of valve trim required to in-hibit hydrate formation.
ASHER GLAUN is a senior engineer and technologist for Masoneilan Control Valves at GE Oil & Gas. He has worked in the control valve industry for over 12 years. Prior to his work with GE Oil & Gas, Mr. Glaun was employed for 11 years at Bird Machine Co. in the design of high-speed centrifuges. His work at GE involves leading new technology development specializing in fluid dynamics, CFD, structural analysis/FEA and valve acoustics.
Mr. Glaun graduated with a BSc degree in mechanical engineering from the University of Cape Town, South Africa, and he obtained an MS degree in mechanical engineering from Northeastern University in Boston, Massachusetts.
JOSEPH SHAHDA is a senior applications engineer for Masoneilan Control Valves at GE Oil & Gas. He has over 16 years of experience in the control valve industry, with a focus on applications engineering and delivering control valves solutions to customers worldwide. Mr. Shahda holds an MS degree in mechanical engineering from Northeastern University in Boston, Massachusetts.
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FIG. 9. CFD temperature plot of a representative 22-turn, multi-stage valve trim. A real gas solver formulation allows for the solving of Joule-Thomson effects.
