ARNOLD, K. (1999). Design of Gas-Handling Systems and Facilities (2nd ed.) Episode 1 Part 5 pps

HEAT EXCHANGER EXAMPLE PROBLEM Design a seawater cooler to cool the total stream from the examplefield in its later stages of life from a flowing temperature of 175°F to atemperature of

86 Design of GAS-HANDLING Systems and Facilities

[text continued from page 83)

Generally, the following design criteria should be provided to the ufacturers or vendors for sizing an exhaust heat recovery unit

man-1 Total heat duty required to heat the fluid

2 Properties of the fluid to be heated

3 The outlet temperature of the heated fluid

4 Operational relationships between heat sources and users (e.g.,which users continue to operate when sources shut down?)

5 Exhaust gas flow rates at anticipated ambient and at various loadsfrom maximum to minimum

6 Exhaust gas temperature at anticipated ambient and at various loads

7 Maximum exhaust back pressure

8 Ambient temperature range

The design of heaters and waste heat recovery units is beyond thescope of this book Sizing and design are best left to manufacturers,However, the concepts discussed in this chapter and in Chapter 2 can beused to verify the manufacturer's proposals

HEAT EXCHANGER EXAMPLE PROBLEM

Design a seawater cooler to cool the total stream from the examplefield in its later stages of life from a flowing temperature of 175°F to atemperature of 100°F to allow further treating

Heat Exchangers 87

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1 Calculate water flow rate in outlet and water vapor condensed

2 Calculate heat duty

3 Determine seawater circulation rate

4 Pick a type of exchanger and number of tubes required

Solution:

1 Calculate free water and water vapor flow rates

Water flow rate in inlet:

Free water = (100 MMscfd)(15 bbl/MMscfd) = 1,500 bwpdWater flow rate in outlet:

Free water = 1,500 bwpd

Water vapor condensed:

Water flow rate in outlet:

2 Calculate heat duty

b Condensate duty

c Free water duty

d Water latent heat duty

e Total heat duty

3 Water circulation rate

Limit AT for water to 10°F to limit scale

4 Heat exchanger type and number of tubes

Choose TEMA R because of large size

Select type AFL because of low temperature change and LMTDcorrection factor

Heat Exchangers 89

The water is corrosive and may deposit solids Therefore, flowwater through tubes and make the tubes 70/30 Cu/Ni Flow thegas through the shell

Calculate LMTD:

Correction factor (Figure 3-10):

Calculate number of tubes:

90 Design of GAS-HANDLING Systems and Facilities

From Table 3-4 for 1-in OD, IM-in, square pitch, fixed tubesheet, four passes, shell ID = 29 in

Use 39-in ID x 20 ft Lg w/682 1-in OD, 10 BWG tubes VA-'m.,

square pitch with four tube passes:

Check the water velocity in tubes From Volume 1:

uThere are four passes Thus, 682/4 tubes are used in each pass,

Comments About Example

Once a specific heat exchanger is chosen, the flow per tube is known,

so it is possible to use the correlations of Chapter 2 to calculate a moreprecise overall heat transfer coefficient (U) An example of calculation of

U is given in Chapter 5

Note that more than 30% of the heat duty was required to cool the waterand condensate If the liquids had first been separated, a smaller exchangerand lower seawater flow rate could have been used In most gas facilities,where cooling is required, the cooler is placed downstream of the first sep-arator for this reason Often an aerial cooler is used for this service

Heat Exchangers 91

In this example we selected a final outlet temperature of 100°F Thiswould be sufficiently low if the gas were only going to be compressedand dehydrated For our case, we must also treat the gas for H2S and CO2removal (Chapter 7) If we chose an amine unit, which we will in all like-lihood, the heat of the reaction could heat the gas more than 10° to 20°F,making the next step, glycol dehydration, difficult (Chapter 8) In such acase, it may be better to cool the gas initially to a lower temperature sothat it is still below 110°F at the glycol dehydrator Often this is not pos-sible, since cooling water is not available and ambient air conditions are

in the 95 °F to 100°F range If this is so, it may be necessary to use anaerial cooler to cool the gas before treating, and another one to cool itbefore dehydration

4 Hydrates *

Resembling dirty ice, hydrates consist of a water lattice in which lighthydrocarbon molecules are embedded They are a loosely-linked crys-talline chemical compound of hydrocarbon and water called cathrates, aterm denoting compounds that may exist in stable form but do not resultfrom true chemical combination of all the molecules involved Hydratesnormally form when a gas stream is cooled below its hydrate formationtemperature At high pressure these solids may form at temperatures wellabove 32°F Hydrate formation is almost always undesirable because thecrystals may cause plugging of flow lines, chokes, valves, and instrumen-tation; reduce line capacities; or cause physical damage This is especiallytrue in chokes and control valves where there are large pressure drops andsmall orifices The pressure drops cause the temperature to decrease, andthe small orifices are susceptible to plugging if hydrates form Hydrateformation leading to flow restrictions is referred to as "freezing."

The two major conditions that promote hydrate formation are (1) the gasbeing at the appropriate temperature and pressure, and (2) the gas being at

or below its water dew point with "free water" present For any particularcomposition of gas at a given pressure there is a temperature below whichhydrates will form and above which hydrates will not form As the pressureincreases, the hydrate formation temperature also increases If there is no

*Reviewed for the 1999 edition by Dennis A Crupper of Paragon Engineering Services, Inc.

92

It is also feasible to design the process so that if hydrates form they can

be melted before they plug equipment

Before choosing a method of hydrate prevention or dehydration, theoperating system should be optimized so as to minimize the necessarytreating Some general factors to consider include the following: (1) reducepressure drops by minimizing line lengths and restrictions, (2) takerequired pressure drops at the warmest conditions possible, and (3) checkthe economics of insulating pipe in cold areas

This chapter discusses the procedures used to calculate the temperature

at which hydrates will form for a given pressure (or the pressure at whichhydrates will form for a given temperature), the amount of dehydrationrequired to assure that water vapor does not condense from a natural gasstream, and the amount of chemical inhibitor that must be added to lowerthe hydrate formation temperature It also discusses the temperature dropthat occurs as gas is expanded across a choke This latter calculation isvital to the calculation of whether hydrates will form in a given stream.The next chapter discusses the use of LTX units to melt the hydrates asthey form, and the use of indirect fired heaters to keep the gas temperatureabove the hydrate formation temperature Chapter 8 describes processesand equipment to dehydrate the gas and keep free water from forming

DETERMINATION OF HYDRATE FORMATION

TEMPERATURE OR PRESSURE

Knowledge of the temperature and pressure of a gas stream at the head is important for determining whether hydrate formation can beexpected when the gas is expanded into the flow lines The temperature atthe wellhead can change as the reservoir conditions or production ratechanges over the producing life of the well Thus, wells that initiallyflowed at conditions at which hydrate formation in downstream equipmentwas not expected may eventually require hydrate prevention, or vice versa

well-94 Design of GAS-HANDLING Systems and Facilities

If the composition of the stream is known, the hydrate temperature can

be predicted using vapor-solid (hydrate) equilibrium constants The basicequation for this prediction is:

where Yn = mol fraction of hydrocarbon component n in gas on a

water-free basis

Kn = vapor-solid equilibrium constant for hydrocarboncomponent n

The vapor-solid equilibrium constant is determined experimentally and

is defined as the ratio of the mol fraction of the hydrocarbon component

in gas on a water-free basis to the mol fraction of the hydrocarbon ponent in the solid on a water-free basis That is:

com-where xn = mol fraction of hydrocarbon component in the solid on a

water-free basis

Graphs giving the vapor-solid equilibrium constants at various atures and pressures are given in Figures 4-1 through 4-4 For nitrogenand components heavier than butane, the equilibrium constant is taken asinfinity

temper-The steps for determining the hydrate temperature at a given systempressure are as follows:

1 Assume a hydrate formation temperature

2 Determine Kn for each component

Hydrates 95

Figure 4-1 Vapor-solid equilibrium constant for (a) methane, (b) ethane, and

n-butane (From Gas Processors Suppliers Association, Engineering Data Book.}

96 Design of GAS-HANDLING Systems and Facilities

Figure 4-2, Vapor-solid equilibrium constant for propane, (from Gas Processors

Suppliers Association, Engineering Data Book, 10th Edition.)

Hydrates 97

Figure 4-3 Vapor-solid equilibrium constants for isobutane (From Gas Processors

Suppliers Association, Engineering Data Book, 10th Edition.)

The presence of H2S should not be overlooked in the determination ofsusceptibility of a gas to form hydrates At concentrations of 30% orgreater, hydrates will form in hydrocarbon gases at about the same tem-perature as in pure H2S

Table 4-1 is an example calculation of the temperature below whichhydrates will form at the 4,000 psia flowing temperature for the examplegas composition of Table 1-1 From this calculation, hydrates will form

at temperatures below 74°F

If the gas composition is not known, this procedure cannot be used todevelop the hydrate formation point Figure 4-5 gives approximatehydrate formation temperatures as a function of gas gravity and pressure.For example, for the 0.67 specific gravity gas of our example field (Table2-10), Figure 4-5 predicts a hydrate formation temperature at 4,000 psia

at 76°F

98 Design of GAS-HAN DUNG Systems and Facilities

Figure 4*4 Vapor-solid equilibrium constants (a) for carbon dioxide, (b) for

hydrogen sulfide (From Gas Processors Suppliers Association, Engineering Data

Book 10th Edition.)

CONDENSATION OF WATER VAPOR

One method of assuring that hydrates do not form is to assure that theamount of water vapor in the gas is always less than the amount required

to fully saturate the gas Typically, but not always, the gas will be

saturat-ed with water in the reservoir As the gas is coolsaturat-ed from reservoir perature, the amount of water vapor contained in the gas will decrease.That is, water will condense

tem-The temperature at which water condenses from natural gas is calledits dew point If the gas is saturated with water vapor, it is by definition

at its dew point The amount of water vapor saturated in the gas is given

Hydrates 99

Table 4-1 Calculation of Temperature for Hydrate Formation at 4,000 psia

in Gas 0.0144 0.0403 0.000019 0.8555 0.0574 0.0179 0.0041 0.0041 0.0063 1.0000 Y/K=1.0at740]

At 70

Kn

Infinity Infinity 0.3

0.95 0.72 0.25 0.15 0.72

Infinity F

°F

yn/i<n

0.00

0.00 0.00 0.90

0.08 0.07 0.03 0.00 0.00 J.08

At 80°

K n

Infinity Infinity 0.5

1 05 1.22

Infinity 0.6

Figure 4-5 Approximate hydrate temperature formation (Courtesy of Smith

Industries, Inc.)

100 Design of GAS-HANDLINCr Systems and facilities

by Figure 4-6 The graph shows the water content in pounds of water perMMscf of saturated gas at any pressure and temperature For example, at150°F and 3,000 psi, saturated gas will contain approximately 105 Ib ofwater vapor per MMscf of gas If there is less water vapor, the gas is notsaturated and its temperature can be reduced without water condensing

If the gas is saturated at a higher temperature and then cooled to L50°Rwater will condense until there are only 105 Ib of water vapor left in thegas The dotted line crossing the family of curves shows the approximatetemperature at which hydrates will probably form at any given pressure.Note the hydrates form more easily at higher pressures

To keep water from condensing as the gas is processed, it is necessary

to dehydrate the gas (that is, remove water vapor) until the amount ofwater vapor remaining in the gas is less than that required to fully satu-rate the gas at all conditions of temperature and pressure Since the dehy-drated gas will have a lower dew point, dehydration is sometimes calleddew point depression For example, if the amount of water vapor in the3,000 psig gas stream referred to earlier were reduced from 105Ib/MMscf to 50 Ib/MMscf, the dew point would be reduced from 150°F

to 127°F That is, its dew point will be depressed by 23°F

Figure 4-6 contains an approximate hydrate formation line Thisshould be used with care, as the position of the line depends on the gascomposition It is better to calculate the hydrate formation temperature oruse Figure 4-5 for approximation

TEMPERATURE DROP DUE TO GAS EXPANSION

Choking, or expansion of gas from a high pressure to a lower pressure,

is generally required for control of gas flow rates Choking is achieved

by the use of a choke or a control valve The pressure drop causes adecrease in the gas temperature, thus hydrates can form at the choke orcontrol valve The best way to calculate the temperature drop is to use asimulation computer program The program will perform a flash calcula-tion, internally balancing enthalpy It will calculate the temperaturedownstream of the choke, which assures that the enthalpy of the mixture

of gas and liquid upstream of the choke equals the enthalpy of the newmixture of more gas and less liquid downstream of the choke

For a single component fluid, such as methane, a Mollier diagram.such as Figure 4-7, can be used to calculate temperature drop directly

Hydrates 101

Figure 4-6 Dew point of natural gas {From Gas Processors Suppliers Association,

Engineering Data Book, 10th Edition.}

4-7, Typical Gas Association, ICHh

er (the temperature drop is 10°F more) than indicated by Figure 4-8.Another technique that can be used to account for the presence of liq-uids is to assume that the water and oil in the stream pass through thechoke with no phase change or loss of temperature The gas is assumed tocool to a temperature given in Figure 4-8 The heat capacity of the liquids

is then used to heat the gas to determine a new equilibrium temperature

3 Generally, an alcohol or one of the glycols—usually methanol, yiene glycol (EG), or diethylene glycol (DEG)—is injected as aninhibitor All may be recovered and recirculated, but the economics

eth-of methanol recovery will not be favorable in most cases

The most common inhibitor in field gas situations, where the inhibitorwill not be recovered and reused, is methanol It is a relatively inexpen-sive inhibitor Methanol is soluble in liquid hydrocarbons, about 0.5% byweight If there is condensate in the stream, additional methanol isrequired because some of that methanol will dissolve in the condensate,Also, some of the methanol vaporizes and goes into the gas state

Ethylene glycol is the most common recoverable inhibitor It is lesssoluble in hydrocarbons and has less vaporization loss than methanol.This is common on the inlet to gas processing plants