Water Hydrocarbon Phase Behavior - Chapter 4

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Water Hydrocarbon Phase Behavior - Chapter 4

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Fundamentals of Oil and Gas Processing Book
Basics of Gas Field Processing Book
Prediction and Inhibition of Gas Hydrates Book
Basics of Corrosion in Oil and Gas Industry Book

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Chapter 4 70
Water Hydrocarbon Phase Behavior 70
4.1 Introduction 70
4.2 Measurements of Water Content of Gases 70
4.2.1 Bureau of Mines Dew-Point Tester (ASTM D 1142-63) 70
4.2.2 Electrolysis Method 72
4.2.3 Aluminum Oxide Humidity Sensor 74
4.2.4 Titration Method 74
4.2.5 Conductivity Cell 75
4.2.6 Dew-Point Tubes 75
4.2.7 Comparison of Methods 75
4.3 Water Content of Natural Gases 77
4.3.1 Water Content of Sweet Gases 77
4.3.2 Water Content of High CO2/H2S Gases 79
4.4 Prediction of Temperature drop due to pressure drop 81
4.5 Hydrates in Natural Gas Systems 82
4.5.1 Conditions which affect hydrate formation are: 85
4.5.2 Prediction of Sweet Natural Gas Hydrate Conditions 85
4.5.3 Hydrate Prediction Based on Composition for Sweet Gases 88
4.5.4 Hydrate Predictions for High CO2/H2S Content Gases 93
4.6 Hydrate Prevention 95
4.6.1 Adding Heat 95
4.6.2 Chemical Injection 96
4.6.3 Hydrate Inhibition with Methanol and Glycols 105
4.6.4 Low Dosage Hydrate Inhibitors (LDHIs) 110

Chapter 4

Water Hydrocarbon Phase Behavior

4.1 Introduction
As produced at the wellhead, natural gases are nearly always saturated with water. When water-saturated natural gas flows in a pipeline the following problems can occur:
1- Liquid water can collect in pipelines and so increase the pressure drop and/or cause slug flow.
2- Free water also can freeze into ice and/or form a solid hydrates and so reduce the gas flow or even plug the line completely.
3- Acid gases (H2S and CO2) dissolve in free water and can cause severe corrosion in internal surface of the pipeline.
Water removal and/or inhibition of hydrate formation is therefore a basic part of gas gathering. Design of oilfield gathering lines, dehydration, and hydrate inhibition facilities require two key phase-behavior predictions:
1- The water content of saturated natural gases
2- The hydrate formation temperate and pressures
4.2 Measurements of Water Content of Gases
Precautions required for gas sampling for dew point measurements are as follows:
1- The gas sample must be representative
2- The sampling line cannot contain free water
3- While flowing in the sample line, the gas must kept above its dew point temperature
4- If a glycol filter is installed, the sample must flow for five minutes (to saturate the filter with water) before the water content is measured.
The water content of natural gases can be measured by six different techniques: dew point, electrolysis, capacitance, conductivity, titration, and IR absorption. In addition dew-point tubes can provide approximate estimate. IR absorption is not used very often, and so the other methods are now summarized.
4.2.1 Bureau of Mines Dew-Point Tester (ASTM D 1142-63)
As shown in fig. 4-1, the Bureau of Mines dew-Point tester consists of a high-pressure, stainless steel or nickel-plated chamber. Gas entering through the inlet valve, A is directed by the deflector, B, onto the chilled, highly-polished stainless steel mirror, C, and then leaves the chamber through the outlet valve, D. The mirror, C, is cooled by cooling tube, F, which is attached to the chiller, G. Refrigerant enters the chiller at valve, H, and leaves at J Any dew on the mirror, C, is observed through the transparent Lucite window, E. The temperature at which dew is observed is read using the calibrated thermometer, K. Mirror M permits simultaneous viewing of the mirror C and reading of the thermometer, K.
Fig. 4-1. Bureau of Mines Dew-Point Tester
Dew-point measurement involves cooling the mirror, C, with a suitable refrigerant (C3 or Freon- 12 down to -20 0F, liquid CO2 down to -90 0F, dry ice/acetone down to –100 0F, or liquid N2 down to – 200 0F); flowing the sample gas over the polished mirror; and reading the temperature and pressure at which dew first appears and disappears on the mirror surface.
The following precautions will improve accuracy:
1- Use an illuminated magnifier and/or an LED temperature readout if the lighting makes it difficult to observe condensation.
2- Purge the tester to remove all air
3- Do not cool the mirror faster than 2 0F/min when within 5 0F dew point
4- While observing the mirror and thermometer, record the temperature at which dew first forms.
5- Let the mirror warm up and observe the temperature at which the dew disappears
6- Repeat steps 4 and 5 until the two temperatures agree within 2 0F
7- Take the average of the two temperatures as the dew point.
Liquid hydrocarbons, alcohols, or glycols also can condensate on the mirror before the water dew point is reached. The following characteristics distinguish water dew points. Refer to figure 4-2.
1- Water dew forms a distinct, opaque, grey circular spot in the center of the mirror (coldest spot). Water should not “wet” the mirror and should resist being blown off the mirror by increasing the gas flow. Ice crystals form an irregular white pattern against the previously –formed, grey water condensate. Barium sulfate and “water-cut” paste can confirm water dew point also.
2- In contrast, liquid-hydrocarbon condensates wet the mirror, expand in rainbow-like rings to cover all mirror, and can be “blown off” or “streak” the mirror by sudden increase in the sample gas flow rate.
3- Alcohol dew point appears as white spots with indistinct edges. Advanced alcohol spots are larger, increasingly white, and eventually form liquid drops that do not freeze.
4- Glycol dew points are darker, cover the entire mirror, and do not evaporate.
With the exception of the thermometer and pressure gauge, the Bureau of mines tester requires no calibration. The method is relatively inexpensive and easy to operate. However, this type of measurement can be time-consuming and cannot be recorded automatically. Accuracy can be very good but varies with the operator skill and dedication.
Fig. 4-2. Dew-point of water, hydrocarbons, and alcohols.
4.2.2 Electrolysis Method
The electrolysis method involves adsorbing and electrolyzing the water vapor in the sample gas. The heart of this instrument is an electrolytic cell consisting of the two 5-mil wires spirally wound throughout the inner wall of the insulating tube. A thin film of phosphorus pentoxide (P2O5) is applied between these two wires which are spaced 5 mil apart. As shown in figure 4-3, the sample gas first flows into the cell, then passes sensing windows covered with a semipermeable membrane, and finally exits. Water vapor, in direct proportional to the sample-gas concentration, is absorbed by the membrane, diffuses into the P2O5 film, and electrolyzed quantitatively. The resulting current is therefore, directly proportional to the water-vapor content of the sample gas.
The cell absorbs and electrolyzes moisture at fractional parts-per-million (ppm) or other units of measure. How: One hundred percent of the sample moisture is absorbed by a phosphorus pentoxide (P2O5) film that covers two spirally-wound electrodes embedded in a hollow glass tube. When the sample gas enters the cell at a known flow rate, the film absorbs all the moisture molecules present. By applying an electrical potential (voltage) to the electrodes, each absorbed water molecule is electrolyzed, generating a finite current. This current is precise and proportional to the amount of absorbed water. It is, therefore, an exact, direct measurement of the water vapor present in the sample gas.
Only the ammeter and flowmeter require calibration, and this makes the electrolytic method one of the most accurate and fundamental available. Ammeter calibration requires “calibration gas” (Natural gas with a known water content). Moisture calibrators provide a continuous supply of calibration gas by saturating the gas with water at 32 0F. Water content from 9.5 to 170 lb/MMscf, can be obtained by varying the calibration gas pressure.
Note the following sources of errors:
1- Contamination of the cell or coating of the P2O5 strip by oil, condensate, glycol, compressor oil, etc. (anything that changes the adsorption of the water vapor). Such a contaminated cell will exhibit a low reading (0.25 lb H2O/MMscf) that will not change when the sample gas flow-rate is varied.
2- Washout of the cell by excess water, alcohol, oil, methane, amine, etc., produces an essentially zero meter reading.
3- A dead short produces an off-scale meter reading.
Models without a semipermeable membrane to protect the P2O5 membrane are far more susceptible to contamination and washout. Two additional warning are worthwhile:
1- The electrolytic cell does not operate well below 32 0F, and should be temperature controlled if necessary.
2- Phosphoric acid can cause severe harm to skin and eyes. Extreme caution should be exercised when the electrolytic cell is cleaned and recoated.
Fig. 4-3. Electrolysis Method.
4.2.3 Aluminum Oxide Humidity Sensor
The moisture sensor consists of a thin, porous layer or film of aluminum oxide (AL2O3) sandwiched between two electrodes. Refere to figure 4-4.
The sandwich sensor is essentially a capacitor, with the AL2O3 the dielectric. When an AC voltage is applied, the resulting impedance varies with the amount of water absorbed in the aluminum oxide film. In turn, the quantity of adsorbed water depends on the partial pressure of the water vapor in the gas sample flowing around the sensor. A suitable electronic circuit converts the measured impedance to the desired units of water vapor content. The sensor or probe is built so that the water vapor equilibrates rapidly.
This capacitance method is used to measure water dew point ranging from -150 to 70 0F with a response time of less than 5 seconds for a 63% step change in moisture content. As with the electrolysis method, contamination by pipe-scale, carbon, salt, and conductive liquids (glycol, methanol) can impede measurement. The sensor is not harmed by liquid slugs of condensate, methanol, glycol, and water. Proper cleaning restores the sensor.
4.2.4 Titration Method
The water content is determined by titration using a water specific reagent (usually Karl Fischer reagent). The sample gas enters the reaction cell, bubbles through a small known quantity of liquid reagent (0.5 mL), and exits via a reagent trap, a pressure reducing regulator, and finally a flow meter. A pair of platinum electrodes, sense the end point of the titration (when the entering water vapor has exhausted the batch of liquid reagent). Then a fresh batch of reagent is injected into the reaction cell by pump.
Electronic circuitry measures the time between end points and the sample gas flow-rate and pressure then it computes and then displays the water content. The entire cycle takes about two seconds.
Karl Fischer reagent is inert to hydrocarbons, carbon oxide, glycol, amines, and most sulfur compounds, e.g., odorizing mercaptans. Hydrogen sulfide will cause the moisture titrator to read high by 0.7 lb H2O/MMscf per grain H2S/100 scf.
Fig. 4-4. Aluminum oxide humidity sensor.
Fig. 4-5. Karl Fischer titrator for moisture content in gas.
4.2.5 Conductivity Cell
The Hygromat measuring cell consists of two stainless steel plates separated and electrically insulated from each other by a ceramic layer. The ceramic layer has eight holes which are partially filled with a hygroscopic salt-glycerol solution. Water is absorbed reversibly by the hygroscopic solution until equilibrium is reached with the surrounding natural gas. In turn the conductivity of the salt-glycerol solution increases as water is absorbed and decreases when water is desorbed.
4.2.6 Dew-Point Tubes
The dew-point tube uses a sampling pump as in figure 4-6. A water detector tube is placed in the pump and 100 mL of pipeline gas is pulled through the tube. The detector tube figure 4-7, is filled with magnesium perchlorate contained in a fine silica gel. Water vapor is absorbed by magnesium perchlorate to produce an alkaline reaction that changes the color of the Hammet’s indicator (crystal violet). The water content in lb/MMscf is read directly from the length of the stain in the detector tube. Overall accuracy is +/- 25%. Alcohols, glycols, and amines cause high readings. The tube range is usually 6-80 lb H2O/MMscf.
4.2.7 Comparison of Methods
- The Bureau of mines dew point method is respected as the one defined by an ASTM standard. Equipment cost is low, but the method is labor intensive in that a single measurements requires approximately 15 minutes. Accuracy varies with operator skill. Uncertainties of +/- 1 0F are attainable for dew points above 32 0F but increase to +/- 4 0F for dew points between -80 to -100 0F.
- The popularity of the electrolytic moisture analyzers is increasing significantly. Their accuracy compares favorably with the dew-point method. Advantages include light weight, probability, continuous readings, fast response times, and ready interfacing with alarms and other process monitors. Improved methods of cleaning and recoating the P2O5 film reduce the most frequent disadvantages of contamination and washout.
- The aluminum oxide sensor is relatively recent and exhibits accuracies and advantages similar to the electrolytic analyzer. It is especially suitable for every dry gases. However, response time is slow and removal of contaminants is more difficult.
- The titrator equipment is relatively expensive but not readily portable. The main advantages are accuracy (3% of reading) and immunity to contaminants, such as glycols and alcohols. The chief disadvantage is the hazardous nature of the Karl Fischer reagents, which creates a disposal problem.
- The advantages of the conductivity method include long-term stability. The 63% response time to sudden changes in gas humidity varies from 5 to 30 minutes depending on gas flow rate and pressure. One disadvantage is that conductivity varies with temperature and so the meter must be kept at constant temperature.
- Detector tubes provide inexpensive approximate estimate. They can be used by nontechnical personnel with minimum training.

Fig. 4-6. Sampling equipment and methods for dew-point tubes.
Fig. 4-7. Dew-point tube readings.
4.3 Water Content of Natural Gases
The saturated water content of a gas depends on pressure, temperature, and composition. The effect of composition increases with pressure and is particularly important if the gas contains CO2 and/or H2S. For lean, sweet natural gases containing over 70% methane and small amounts of heavy hydrocarbons, generalized pressure-temperature correlations are suitable for many applications.
4.3.1 Water Content of Sweet Gases
Fig. 4-8 is an example of one such correlation which has been widely used for many years in the design of “sweet” natural gas dehydrators. The gas gravity correlation should never be used to account for the presence of H2S and CO2 and may not always be adequate for certain hydrocarbon effects, especially for the prediction of water content at pressures above 1500 psia. The hydrate formation line is approximate and should not be used to predict hydrate formation conditions.

Example 4-1 — Determine the saturated water content for a sweet lean hydrocarbon gas at 150°F and 1,000 psia.
From Fig. 4-8, W = 220 lb/MMscf.
For a 26 molecular weight gas, Cg = 0.98 (Correction for gas gravity- fig. 4-8)
W = (0.98)(220) = 216 lb/MMscf
For a gas in equilibrium with a 3% brine, Cs = 0.93 (Correction for salinity fig. 4-8)
W = (0.93)(220) = 205 lb/MMscf
Fig. 4-8. Water Content of sweet Hydrocarbon Gas. McKetta and Wehe, 1958; GPSA, 1987.
4.3.2 Water Content of High CO2/H2S Gases
Saturated water content of pure CO2 and H2S can be significantly higher than that of sweet natural gas, particularly at pressures above about 700 psia at ambient temperatures.
Corrections for H2S and CO2 should be applied when the gas mixture contains more than 5% H2S and/or CO2 at pressures above 700 psia. These corrections become increasingly significant at higher concentrations and higher pressures.
Below 40% acid gas components, one method of estimating the water content uses Eq 4-1 and Fig. 4-8, 4-9, and 4-10.

W = yHC WHC + yCO2 WCO2 + yH2SWH2S Eq 4-1

W = Water content of gas, lb/MMscf
yHC = Mole fraction of hydrocarbon in the gas phase
WHC = Water content in hydrocarbon gas, lb/MMscf
YCO2 = Mole fraction of CO2 in the gas phase
WCO2 = Effective water content in CO2 gas, lb/MMscf
yH2S = Mole fraction of H2S in the gas phase
WH2S= Effective water content in H2S gas, lb/MMscf

Fig. 4-9. Effective Water Content of H2S in Natural Gas Mixtures vs. Temperature at Various Pressures

Fig. 4-10. Effective Water Content of CO2 in Natural Gas Mixtures vs. Temperature at Various Pressures

Note that Fig. 4-9 and 4-10 provide values for what is termed the “effective” water content of CO2 and H2S in natural gas mixtures for use only in Eq 4-1. These are not pure CO2 and H2S water contents.

A second method is Fig. 4-11. The CO2 is converted to equivalent H2S, using the factor 70%.

Example 4-2 — Determine the saturated water content of an 80% C1, 20% CO2 mixture at 160 °F and 2000 psia. The experimentally determined water content was 172 lb/MMscf.

Method One
WHC = 167 lb/MMscf (Fig. 4-8)
WCO2 = 240 lb/MMscf (Fig. 4-10)
W = (0.80 x 167) + (0.20 x 240)
=182 lb/MMscf

Method Two
First the composition must be converted for use with Fig. 4-11.
yH2S (pseudo) = 0.70 (yCO2 ) = 0.70 (0.20) = 0.14
Enter the left side of Fig. 4-11 at 160°F and move to the % H2S Equivalent line (14%). Proceed vertically upward to the Pressure, psia line (2000 psia), and move horizontally to the left to Water Content Ratio scale (ratio of 1.16).
W = (1.16)(167) = 194 lb/MMscf
Fig.4-11 . Calculated Water Content of Acid Gas Mixtures.
4.4 Prediction of Temperature drop due to pressure drop
Figure 4-12 can be used to get a quick approximate solution for the temperature drop of a natural gas stream (accuracy is +/- 5%.). For example, if the initial pressure is 4,000 psi and the final pressure is 1,000 psi, P is 3,000 psi, the change in temperature is 80°F. This curve is based on a liquid concentration of 20 bbl/MMscf. The greater the amount of liquid in the gas the lower the temperature drop, that is, the higher the calculated final temperature. For each increment of 10 bbl/MMscf there is a correction of 5°F. For example, if there is no liquid, the final temperature is 10°F cooler (the temperature drop is 10°F more) than indicated by Figure 4-12.

Example 4-3: Determine the temperature drop across a choke
Given: A well with a flowing tubing pressure of 4000 psi and 20 bbl of hydrocarbon condensate and a downstream back pressure of 1000 psi.
Solution: Initial pressure = 4000 psi
Final pressure = 1000 psi , P = 3000 psi
From Figure 4-12 correlation; intersect initial pressure = 4000 and ΔP-3000 read ΔT = 800F.

4.5 Hydrates in Natural Gas Systems
A hydrate is a physical combination of water and other small molecules to produce a solid which has an “ice-like” appearance but possesses a different structure than ice. Their formation in gas and/or NGL systems can plug pipelines, equipment, and instruments, restricting or interrupting flow.
There are three recognized crystalline structures for such hydrates. Where, water molecules build the lattice and hydrocarbons, nitrogen, CO2 and H2S occupy the cavities. Smaller molecules (CH4, C2H6, CO2, H2S) stabilize a body-centered cubic called Structure I. Larger molecules (C3H8, i-C4H10, n-C4H10) form a diamond-lattice called Structure II.
Normal paraffin molecules larger than n-C4H10 do not form Structure I and II hydrates as they are too large to stabilize the lattice. However, some isoparaffins and cycloalkanes larger than pentane are known to form Structure H hydrates.

Gas composition determines structure type. Mixed gases will typically form Structure II. From a practical viewpoint, the structure type does not affect the appearance, properties, or problems caused by the hydrate. It does however, have a significant effect on the pressure and temperature at which hydrates form. Structure II hydrates are more stable than Structure I. This is why gases containing C3H8 and i-C4H10 will form hydrates at higher temperatures than similar gas mixtures which do not contain these components. The effect of C3H8 and i-C4H10 on hydrate formation conditions can be seen in Fig. 4-15. At 1000 psia, a 0.6 sp. gr. gas (composition is shown in Fig. 4-15) has a hydrate formation temperature which is 12-13°F higher than pure methane.

Fig.4-13. Hydrate structures, typical hydrate plugging, and illustration of hydrate formation.

Fig. 4-14. Conditions for Hydrate Formation for Light Gases
Fig. 4-15. Pressure-Temperature Curves for Predicting Hydrate Formation. Katz.1945.GPSA 1987.

The presence of H2S in natural gas mixtures results in a substantially warmer hydrate formation temperature at a given pressure. CO2, in general, has a much smaller impact and often reduces the hydrate formation temperature at fixed pressure for a hydrocarbon gas mixture.
4.5.1 Conditions which affect hydrate formation are:

Primary Considerations
• Gas or liquid must be at or below its water dew point or saturation condition (Note: liquid water does not have to be present for hydrates to form)
• Temperature
• Pressure
• Composition
Secondary Considerations
• Mixing
• Kinetics
• Physical site for crystal formation and agglomeration such as a pipe elbow, orifice, thermowell, or line scale
• Salinity
In general, hydrate formation will occur as pressure increases and/or temperature decreases to the hydrate formation condition.

4.5.2 Prediction of Sweet Natural Gas Hydrate Conditions
Fig. 4-14, based on experimental data, presents the hydrate pressure-temperature equilibrium curves for pure methane, ethane, propane, and for a nominal 70% ethane 30% propane mix.
Fig. 4-15 through 4-19, based on gas gravity, may be used for first approximations of hydrate formation conditions and for estimating permissible expansion of sweet natural gases without the formation of hydrates.
The conditions at which hydrates can form are strongly affected by gas composition.

Example 4-4- Find the pressure at which hydrate forms for a gas with the following composition. T = 50°F.
Table 4-1. Gas composition and molecular weight calculation for Example 4-4.
Gas specific gravity = MWgas/MWair = 20.08/28.964 = 0.693
From Fig. 4-15 at 50°F.
P = 320 psia for 0.7 gravity gas

Example 4-5— The gas in Example 4-4 is to be expanded from 1,500 psia to 500 psia. What is the minimum initial temperature that will permit the expansion without hydrate formation?
The 1,500 psia initial pressure line and the 500 psia final pressure line intersect just above the 110°F curve on Fig. 4-17. Approximately 112°F is the minimum initial temperature.

Example 4-6 — How far may a 0.6 gravity gas at 2,000 psia and 100°F be expanded without hydrate formation?
On Fig. 4-16 find the intersection of 2,000 initial pressure line with the 100°F initial temperature curve. Read on the x-axis the permissible final pressure of 1100 psia.

Fig. 4- 16. Permissible Expansion of a 0.6-Gravity Natural Gas Without Hydrate Formation

Example 4-7 — How far may a 0.6 gravity gas at 2,000 psia and 140°F be expanded without hydrate formation?
On Fig. 4-16, the 140°F initial temperature curve does not intersect the 2,000 psia initial pressure line. Therefore, the gas may be expanded to atmospheric pressure without hydrate formation.

Conditions predicted by Fig. 4-15 through 4-19 may be significantly in error for compositions other than those used to derive the charts. For more accurate determination of hydrate formation conditions, the following procedures should be followed. In addition, fig. 4-15 through 4-19, do not account for liquid water and liquid hydrocarbons present or formed during the expansion. These can have a significant effect on the outlet temperature from the pressure reduction device.

Fig. 4- 19. Permissible Expansion of a 0.9-Gravity Natural Gas Without Hydrate Formation

4.5.3 Hydrate Prediction Based on Composition for Sweet Gases

1- Katz’s Graph
The first method is for approximate and fast prediction, using of Katz graph represented in figure 4-15. On the other hand, for below 1,000 psi (70 bar), the figure can be approximated by:

t(°F) = −16.5 – [6.83/(SpGr)2] + 13.8 ln[P(psia)] Eq 4-9.

2- Katz’s Vapor solid equilibrium method
Several correlations have proven useful for predicting hydrate formation of sweet gases and gases containing minimal amounts of CO2 and/or H2S. The most reliable ones require a gas analysis. The Katz method utilizes vapor solid equilibrium constants defined by the Eq 4-10.

Kvs = y / xs Eq 4-10
Kvs = vapor/solid equilibrium K-value
y = mole fraction in the gas phase
xs = mole fraction in the solid phase

WARNING: Not good for pure components – only mixtures.
The Katz’s correlation is not recommended above 1000-1500 psia, depending on composition.
The applicable K-value correlations for the hydrate forming molecules (methane, ethane, propane, isobutane, normal butane, carbon dioxide, and hydrogen sulfide) are shown in Fig. 4-20 to 4-26. Normal butane cannot form a hydrate by itself but can contribute to hydrate formation in a mixture.
For calculation purposes, all molecules too large to form hydrates have a K-value of infinity. These include all normal paraffin hydrocarbon molecules larger than normal butane.
Nitrogen is assumed to be a non-hydrate former and is also assigned a K-value of infinity.
The Kvs values are used in a “dewpoint” equation to determine the hydrate temperature or pressure. The calculation is iterative and convergence is achieved when the following objective function (Eq 4-3) is satisfied.

∑y/Kvs = 1.0 Eq. 4-11
Fig. 4- 20. Kvs. Vapor solid equilibrium constants for Methane.
Fig. 4- 21. Kvs. Vapor solid equilibrium constants for Ethane.
Fig. 4- 22. Kvs. Vapor solid equilibrium constants for Propane.
Fig. 4- 23. Kvs. Vapor solid equilibrium constants for Iso-Butane.
Fig. 4- 24. Kvs. Vapor solid equilibrium constants for N-Butane.

Fig. 4- 25. Kvs. Vapor solid equilibrium constants for carbon dioxide.
Fig. 4- 26. Kvs. Vapor solid equilibrium constants for hydrogen sulfide.

Example 4-8 — Calculate the pressure for hydrate formation at 50°F for a gas with the following composition.

Table. 4-2. Example. 4-8.
The ∑y/Kvs value is slightly over than 300 psia, by iterpolating linearly, = 1.0 @ 305 psia.
Hydrate pressure at temperature 50 0F = 305 psia
Third and fifth columns are values obtained from chart for each component at temperature and pressure values.
Fourth column contains the results of dividing Mole fraction of gas by third column.
Sixth column contains the results of dividing Mole fraction of gas by fifth column.
3- Motiee (1991) suggested the following equation for hydrate temperature prediction:
T(0F) = -238.24469 + 78.99667 log P(psi) – 5.352544 (log P(psi) )2 +
349.473877 y – 150.854675 y2 – 27.604065 y log P(psi) Eq. 4-12
Where ᵞ is gas specific gravity.
This equation is well known and widely used in the oil and gas industry because of its accuracy for natural gas mixtures.
4- Recently (2009), a new correlation developed by Bahadori and Vuthaluru, with specific gravities from 0.55 to 1, shows the best efficiency. The equation is suitable for estimating the HFT, especially for natural gas mixtures:
T(k) = AyB (ln P(KPa))C Eq. 4-13
0F = (0K - 273.15) x 9/5 + 32
0K = (0F - 32) x 5/9 + 273.15
psi = 6.895 KPa,
4.5.4 Hydrate Predictions for High CO2/H2S Content Gases
The Katz method of predicting hydrate formation temperature gives reasonable results for sweet paraffin hydrocarbon gases. The Katz method should not be used for gases containing significant quantities of CO2 and/or H2S despite the fact that Kvs values are available for these components. Hydrate formation conditions for high CO2/H2S gases can vary significantly from those composed only of hydrocarbons. The addition of H2S to a sweet natural gas mixture will generally increase the hydrate formation temperature at a fixed pressure. A method by Baille & Wichert for predicting the temperature of high H2S content gases is shown in Fig. 4-27.
Fig.4-27. Hydrate Chart for Gases Containing H2S
4.6 Hydrate Prevention
Hydrate prevention is accomplished by keeping the:
1- Operating conditions must remain out of the hydrate-formation zone by heating or temperature control.
2- Hydrate point must be maintained below the operating conditions of the system by chemical treatment.

Two common methods of hydrate-formation prevention are:
1- Temperature control
2- Chemical injection

Example 4-9 — Estimate the hydrate formation temperature at 610 psia of a gas with the following analysis using Fig. 4-27.

Table. 4-3. Solution of example 4-9.
MW = 19.75
Sp.Gr (ᵧ) = 0.682

Solution Steps:
1. Enter left side of Fig. 4-27 at 600 psia and proceed to the H2S concentration line (4.18 mol%)
2. Proceed down vertically to the specific gravity of the gas (ᵞ = 0.682)
3. Follow the diagonal guide line to the temperature at the bottom of the graph (T = 63.5°F).
4. Apply the C3 correction using the insert at the upper left.
Enter the left hand side at the H2S concentration and proceed to the C3 concentration line (0.67%). Proceed down vertically to the system pressure and read the correction on the left hand scale (–2.7°F)

Note: The C3 temperature correction is negative when on the left hand side of the graph and positive on the right hand side.
TH = 63.5 −2.7 = 60.8°F
Fig. 4-27 was developed based on calculated hydrate conditions using the Peng-Robinson EOS. It has proven quite accurate when compared to the limited amount of experimental Mole Fraction data available. It should only be extrapolated beyond the experimental data base with caution.

4.6.1 Adding Heat
Adding heat is effective because hydrates normally do not occur above 70 0F.
It offers a simple and economical solution for land and offshore facilities (if waste heat is available).
Flow stream is preheated, either through an indirect line heater or heat exchanger, before passing through a choke. Flow stream is then reheated to maintain the temperature above the hydrate formation temperature.
A major drawback in offshore installations is that it is almost impossible to maintain flowline temperatures significantly above the water temperature if the flowlines extend more than a few hundred feet under water. Thus, either the “free water” must be separated while still at temperature or an alternate method
selected. Temperature Control
Wellhead Indirect Heaters
An indirect heater is used to heat gas to maintain temperatures above that of the hydrate formation.
It consists of an atmospheric vessel containing a fire tube (usually fired by gas, steam, or heating oil) and a coil (designed to withstand shut in tubing pressure “SITP”) that is heated by the intermediate fluid (usually water) and the fluid is heated. The fire tube and coil are immersed in a heat transfer fluid (normally water), and heat is transferred to the fluid in the coil.
Figure 4-28 shows a typical heater installation at the wellhead.

Long-Nose Heater Choke (Figure 4-29).
A long body choke installed in the indirect heater to position the choke orifice within the indirect heater bath. Since the walls of the choke orifice are heated by the water bath, hydrates will not form in the orifice and cause plugging.

Flowline indirect Heaters
Flowline heaters differ from wellhead heaters in purpose only.
The purpose of a wellhead heater is to heat the flow stream at or near the wellhead where choking or pressure reduction occurs.
The purpose of a flowline heater is to provide additional heat if required.
The design is the same as an indirect heater except that the choke, shut-in, and relief equipment are seldom used.

System Optimization
System operation has to be optimized before heaters can be effectively designed and located.
Heat requirements that appear to be large can often be reduced to minimal values or even eliminated by revising the mode of operation. For example: Fields having multiple producing wells can be combined to use higher flowing temperatures thus minimizing heater requirements.
If reducing the gas stream pressure is necessary, it is generally more efficient to do so at a central point where the necessary heater fuel gas can be obtained from separators or scrubbers.
Requires flowline wall thickness to be increased so as to withstand wellhead SITP.
An alternative is to install wellhead shut-down valves and flowline high pressure switches.

Downhole Regulators
Downhole regulators are feasible for high capacity gas wells at locations where certain risks to other downhole equipment are acceptable. The theory behind the use of a downhole regulator is that the pressure drop from flowing pressure to near-sales line pressure is taken downhole where the formation temperature is sufficient to prevent hydrate formation. The tubing string above the regulator then acts as a subsurface heater. Calculations involved in downhole regulator design are rather involved. They depend on characteristics such as:
Wellbore configuration, flowing downhole pressures and temperature, and well depth.
Although shortcut procedures are available to estimate the feasibility of downhole regulators, tool company representatives can provide detailed design information.

4.6.2 Chemical Injection
The formation of hydrates can also be prevented by dehydrating the gas or liquid to eliminate the formation of a condensed water (liquid or solid) phase. In some cases, however, dehydration may not be practical or economically feasible. In these cases, chemical inhibition can be an effective method of preventing hydrate formation. Chemical inhibition utilizes injection of thermodynamic inhibitors or low dosage hydrate inhibitors (LDHIs). Thermodynamic inhibitors are the traditional inhibitors (i.e., one of the glycols or methanol), which lower the temperature of hydrate formation. LDHIs are either kinetic hydrate inhibitors (KHIs) or antiagglomerants (AAs).
They do not lower the temperature of hydrate formation, but do diminish its effect. KHIs lower the rate of hydrate formation, which inhibits its development for a defined duration.
AAs allow the formation of hydrate crystals but restrict them to sub-millimeter size.

Fig. 4-28. Wellhead indirect heater schematic. Thermodynamic Inhibitors
Inhibition utilizes injection of one of the glycols or methanol into a process stream where it can combine with the condensed aqueous phase to lower the hydrate formation temperature at a given pressure.
Both glycol and methanol can be recovered with the aqueous phase, regenerated and re-injected. For continuous injection in services down to –40°F, one of the glycols usually offers an economic advantage versus methanol recovered by distillation.
At cryogenic conditions (below –40°F) methanol usually is preferred because glycol’s viscosity makes effective separation difficult.
Ethylene glycol (EG), diethylene glycol (DEG), and triethylene glycol (TEG), glycols have been used for hydrate inhibition. The most popular has been ethylene glycol because of its lower cost, lower viscosity, and lower solubility in liquid hydrocarbons.

Freezing point of aqueous methanol solution is given in fig. 4-30.
Hydrate inhibitors are used to lower the hydrate formation temperature of the gas.
Recovery and regeneration steps are used in all continuous glycol injection projects and in several large-capacity methanol injection units.
Injection of hydrate inhibitors should be considered for the following applications:
• Pipeline systems in which hydrate trouble is of short duration
• Gas pipelines that operate at a few degrees below the hydrate formation temperature
• Gas-gathering systems in pressure-declining fields
• Gas lines in which hydrates form as localized points
Methanol and the lower molecular weight glycols have the most desirable characteristics for use as hydrate inhibitors.
When hydrate inhibitors are injected in gas flowlines or gathering systems, installation of a free-water knockout (FWKO) at the wellhead proves to be economical in nearly every case.
Removing the free water from the gas steam reduces the amount of inhibitor required.
To be effective, the inhibitor must be present at the very point where the wet gas is cooled to its hydrate temperature. For example, in refrigeration plants glycol inhibitors are typically sprayed on the tube-sheet faces of the gas exchangers so that it can flow with the gas through the tubes. As water condenses, the inhibitor is present to mix with the water and prevent hydrates. Injection must be in a manner to allow good distribution to every tube or plate pass in chillers and heat exchangers operating below the gas hydrate temperature.
Table 4-4 lists some physical properties of methanol and the lower molecular weight glycols.

The inhibitor and condensed water mixture is separated from the gas stream along with a separate liquid hydrocarbon stream. At this point, the water dewpoint of the gas stream is essentially equal to the separation temperature. Glycol-water solutions and liquid hydrocarbons can emulsify when agitated or when expanded from a high pressure to a lower pressure, e.g., JT expansion valve. Careful separator design will allow nearly complete recovery of the diluted glycol for regeneration and reinjection.

Fig. 4-29. Indirect heater and long-Nose choke.

Fig. 4-30. Freezing Points of Aqueous Methanol Solutions

Methanol Injection Considerations
Methanol is well-suited for use as a hydrate inhibitor because it is:
Nonreactive chemically with any constituent of the gas
Soluble in all proportions in water
Volatile under pipeline conditions
Reasonable in cost
Of a vapor pressure greater than that of water
Methanol is injected by means of an injection pump (3 in Figure 4-31) into the flowline upstream of the choke or pressure control valve (2). A temperature controller may be installed to measure the temperature of the gas in the low-pressure flowlineand adjusts the methanol rate accordingly.

Fig. 4-31. Methanol injection system at wellhead.

Glycol Injection Considerations
Glycol has a relatively low vapor pressure and thus does not evaporate into the vapor phase as readily as methanol. The solubility of glycol in liquid hydrocarbons is relatively low. For the above reasons, glycol can be more economically recovered, thus reducing the operating expenses below those of methanol systems. The injection part of the system (items 1 to 5 in Figure 4.32) is similar to the methanol injection system. Taking into consideration that, the viscosities of ethylene glycol and its aqueous solutions increase significantly as temperature decreases. Additional equipment in the glycol system is for recovering and reclaiming the glycol. A three-phase separator (6) separates the water and glycol from the hydrocarbon phases. The water–glycol solution in the separator is sent to the reboiler (7) while gas is delivered to the sales line, and the hydrocarbon condensate is dumped to the condensate storage tanks.
In the reboiler, excess water is boiled away from the glycol. The glycol reconcentrated in the reboiler is then available again for injection into the gas stream. Separation of the glycol water phase from the hydrocarbon-liquid field requires a temperature above 700F and a residence time of 10 to 15 minutes.

Nozzle Design (Figure 4-33)
Due to the vapor pressure of glycol, a fine, well-distributed mist is required to obtain adequate mixing with the gas to ensure optimum results, thus spray nozzles are normally used. Nozzle selection is a major consideration in the design of cold separation facilities or plants using glycol injection. Glycol injection normally takes place just upstream of a heat exchanger or chiller where gas is being chilled. Proper nozzle selection will ensure that the glycol spray covers the tube sheet. 100 to 150 psi differential pressure at the nozzle is sufficient to atomize the glycol.
Process stream velocities should be at least 12 ft/s.

Fig. 4-32. Glycol injection system at wellhead.

Fig. 4-33. Schematic of a spray nozzle used in glycol injection.

Glycol Selection General Guideline
The three glycols normally used to prevent the formation of hydrates are:
• Ethylene glycol (EG)
• Diethylene glycol (DEG)
• Triethylene glycol (TEG)
Selection of a glycol depends on the composition of the hydrocarbon flow stream as follows:

1- If glycol is to be injected into a natural gas transmission line where glycol recovery is of less importance than hydrate protection, ethylene glycol is the best choice because it produces the greatest hydrate depression and has the highest vapor pressure of any of the glycols.
2- If glycol is to be injected into a unit where it will contact hydrocarbon liquids, ethylene glycol is preferred because it has the lowest solubility in high molecular weight hydrocarbons.
3- If vaporization losses are severe, either diethylene or triethylene glycol are the best choice because both have a lower vapor pressure. Sometimes diethylene glycol is used if there is a combined loss of both gas vaporization and liquid solubility.
4- The freezing point of the glycol solution must be lower than the lowest temperature expected in the system. In inhibitor service, glycol concentrations are usually maintained at 70 to 75 weight percent because freezing of the glycol is not a problem at this concentration.
5- Reboiler temperature is dependent on the type of glycol and its concentration.
6- Temperature should be maintained at a level equal to the boiling point of the desired solution.
7- Boiling points for the three glycol types are plotted in Figures 4-34, and 4-35.

For example, from Figure 4-34 the reboiler temperature should be set at 240 0F in order to produce about 70 weight percent ethylene glycol solution at atmospheric pressure (N.B. 760 mm, Hg= 1 atm. Pressure.). Thermal degradation can occur if the boiling point of the pure glycol is exceeded; it should therefore be avoided. Glycol losses for the two-phase gas condensate systems are normally estimated at 1 to 2 gallons per 100 barrels of hydrocarbon liquid produced. Vaporization into the gas stream and solution into the hydrocarbon liquid usually cause only a small portion of the total loss.
The most significant causes of glycol losses are leakage and carryover with the hydrocarbon liquid. Loses also occur from vaporization and carry over in the reboiler.

Fig. 4-34. Boiling and condensation points of Ethylene and Di-ethylene glycol.
Fig. 4-35. Boiling and condensation points of Tri-ethylene glycol.
Chemical Injection System
The three parts of an injection system are:
Pump, meter, and control system

Single-Point Chemical Injection
A single pump, meter, and control system service one injection point.
Disadvantages are:
1- Limited turn-down capability and increased life-cycle cost
2- Weight and space increase as injection points increase

Multi-Point Chemical Injection
A shared pump and multiple meter and control devices servicing multiple injection points.
1- Increased turn-down capacity.
2- Per well capital investment decreases as the number of wells increases
3- Injection points are easily added
4- Lower weight and space requirements for higher quantity well applications
1- Instrumentation intensive, and multiple control loops required
2- Requires variable speed for fixed crank pumps
3- Experiences high-pressure drops from header to recycle line
Metering Pump Types:
Diaphragm Pumps
Hermetically sealed, no contamination to atmosphere
Long-life diaphragms typically greater than 2 years continuous duty (20,000 hours)
Long-life of hydraulic plunger seals, typically greater than 2 years continuous duty.
Internal hydraulic relief
Maximum safeguard to environment and personnel safety.
Higher purchase price
More complex maintenance required

Plunger Pumps
Lower purchase price
Less complicated maintenance (easier to understand)
Plunger packing service life typically less than 2000 hours
Friction between plunger and packing

Comparison of Hydrate Prevention Methods
The four methods (indirect heaters, methanol injection, glycol injection, and downhole regulators) discussed above are proven safe and reliable.
Evaluation should consider:
1- Development of CAPEX and OPEX (including chemicals and fuel)
2- Space needs (especially in offshore operations) and operating hazards.

1- Capital costs and the fuel expense of heaters are relatively large, and it is difficult to maintain a clean, reliable fuel supply to remote heater locations.
2- Indirect heater requires a large amount of space.
3- Fire boxes with proper flame arrestors have minimized the hazards from fired equipment, but they should be bought with strict attention paid to detailed design.

Chemical Injection
Advantages and disadvantages of methanol injection and glycol injection are listed in Table 4-5.
The use of methanol requires only a free-water separator and a suitable means for injection and atomizer, whereas the use of glycol requires a free-water separator plus a gas–liquid separator and a glycol reconcentration unit at the point of recovery downstream.

Downhole Regulators
No routine service is required on downhole regulators, but a wireline service company must be used each time the pressure drop has to be changed and when the regulator is removed. A well with a downhole regulator may require injection of methanol or glycol when it is brought back online after a shut-in until the flow and temperature stabilize. After a well declines to less than allowable production, the downhole regulator will have to be removed, and another form of hydrate prevention may prove necessary.
Downhole regulators do not present special safety hazards, but because work with regulators involves working in the well, losing the well is always a danger.

Inhibitor Advantages Disadvantages
Methanol Relatively low initial cost Minimal equipment
Simple system
High operating cost
Hauling to site necessary
Disposal procedures and precautions for water-methanol mixture
Glycol Usually lower operating cost than methanol when both systems recover chemical
Simple system High initial cost
Hauling to site necessary
Large loss if line breaks
Table 4-5 Methanol and Glycol Injection Comparisons

Summary of Hydrate Prevention Methods:
The methanol injection system is often used for temporary hydrate prevention service in small installations.
Larger installations are favored for indirect heaters or glycol injection systems.
Downhole regulators are most useful in large high-pressure reservoirs in which excess pressure is available and the reservoir pressure is not expected to decline rapidly.

Table 4-6 contains a summary comparison of the above methods.
4.6.3 Hydrate Inhibition with Methanol and Glycols
The amount of chemical inhibitor required to treat the water in order to lower the hydrate formation temperature may be calculated from the Hammerschmidt equation:

ΔT = KWR / M (100-WR) Eq. 4- 14
ΔT is the depression in hydrate formation temperature (0F),
WR is weight percent of inhibitor for water treatment,
K is a constant that depends on the type of inhibitor (table 4-7), and
M is the molecular weight of the inhibitor (table 4-7)

Table. 4-7. M and K values for hydrate inhibitors.

Once the required inhibitor concentration has been calculated, the mass of inhibitor required in the water phase may be calculated from the following equation:
Amount of inhibitor (mI) for water phase for each lb/MMscf

mI = WR X lbH2O/MMscf /(1- WR) Eq. 4-15
Or in general equation
mI = WR X mH2O / (WL − WR) Eq 4-16
mI = Amount of Inhibitor (lb)
mH2O = Amount of water (lb)
WR = weight percent of inhibitor for water treatment,
WL = Lean inhibitor concentration (for example, 80% EG; WL =0.8, 100% methanol; WL=1, etc.)

Fig. 4-36 . Ratio of methanol vapor composition to methanol liquid composition

Determination of Total Inhibitor Required
Total inhibitor required =
Inhibitor required for free water + Inhibitor lost to vapor phase + Inhibitor soluble in condensate
Where inhibitor lost to vapor phase is determined from Figure 4-36. (Methanol lost to the vapor phase), while glycol vaporization losses are generally very small and are typically ignored in calculations.
Inhibitor soluble in the condensate is determined from Figure 4-37 and a value of approximately 0.5% can be used. Solubility of EG in the liquid hydrocarbon phase is extremely small. A solubility of 0.3 lb per 1000 gal. (U.S.) of NGL is often used for design purposes.
Engineering Data Book “GPSA 2004”, recommended that Eq 4-15, should not be used beyond 20-25 wt% for methanol and 60-70 wt% for the glycols. For methanol concentrations up to about 50%, the Nielsen-Bucklin equation (4-17) provides better accuracy:

ΔT 0F =−129.6 ln (zH2O) Eq 4-17
z = mole fraction in the liquid phase
zH2O is mole fraction of water
Mole fraction of inhibitor, zI = 1 - zH2O.
WR = (MI X zI ) / (MI X zI + 18 X zH2O) Eq.4-18
MI = Molecular weight of inhibitor
For methanol, WR = (32 X zI )/ (32 X zI + 18 X zH2O). (Examples 4-10, and 4-11 will explain).

Fig. 4-37. Solubility of Methanol in Paraffinic Hydrocarbons vs. Temperature at Various Concentrations

Example 4-10: Determining the Amount of Methanol Required in a Wet Gas Stream
Flow rate
Gas= 20 MMscfd (Sp.Gr = 0.600)
Condensate = 800 bpd (60 0API/ SP.Gr.=0.739) = 40 bbl/MMscf
Produced Water = 60 Bwpd (Sp.Gr.= 1.03) = 3 bbl/MMscf

Upstream choke
FWHP = 3000 psia (P1)
FWHT = 100 0F (T1)
Down stream choke (cold line)
FWHP = 2000 psia (P2)
FWHT = 60 0F (T2)
Determine: Calculate the total methanol required to prevent hydrates from forming.

Fig. 4-38. Example 4-9.
1. The amount of water that will be condensed is determined from McKetta-Wehe (Figure 4-8), assuming the gas is saturated at wellhead conditions.
Water content upstream choke @ 3,000 psia & 100 0F = 32.0 Ib/MMscf
Water content downstream choke @ 2,000 psia & 60 0F = 11.5 lb/MMscf

Water Condensed =(32.0 – 11.5) = 20.5 lb/MMscf
Produced Water = ‏ (1.03 X 2.205 X 159) = (361 lb/bbl) X 3 = 1083 lb/MMscf
Total water = (20.5 + 1083) =1103.6 Ib/MMscf

2. From pressure-temperature curve, the hydrate formation temperature is 68 0F (refer to Figure 4-15), or according to equation 4-12, or Equation 4-13 Hydrate formation temperature is 66 0F.
(In this calculation, we will consider the value 68 0F)
The required dewpoint depression then is 68 0F– 60 0F = 8 0F
3. The concentration of methanol required in the liquid water phase from Equation 4-14 is:
8 0F = 2335 WR / 32 (100 – WR)
Rearranging and solving for WR = 9.892% = 0.09892
4. Therefore, from equation 4-15, the estimated methanol required in the liquid water phase is:
mI = 0.09892 x 1103.65 / (1 – 0.09892 ) = 121 lb/MMscf
or we can use equation mI = WR X mH2O / (WL − WR) Eq 4-16
5. From Figure 4-36, the methanol that will flash into the vapor phase at 2000 psia and 60 0F is
= n lbs.methanol/MMscf / WT% methanol in water phase = 1.52
6. Therefore, the methanol in the vapor phase (n) is:
n= 1.52 X 9.892% =15 lb/MMscf
7. A barrel of our condensate weighs:
= [0.739 x 2.205 (lb per liter water) x 159 (liter per barrel)] = 259 lb/bbl
8. Therefore, the approximate amount of methanol soluble in the condensate or liquid hydrocarbon phase (assuming a 0.5% solubility by weight) = 0.005 x 259 x 40 = 52 lb/MMscf
9. Thus, the total amount of methanol required is:
Total = liquid water phase (121) + Vapor phase (15) + Soluble in condensate (52) =188 lb/MMscf
Total = (188 lb/MMscf) x (20 MMscfd) = 3760 lb/day

Note that for gas-condensate wells producing a reasonable or high amount of condensate, the amount of methanol soluble in the condensate is crucial to determining the amount needed.
Approximately 188 lb of methanol must be added so that approximately 121 lb will be dissolved into the water phase.
Since the specific gravity of methanol is 0.791 (at 68 0F), this is equivalent to:
= 188/ [0.791 x 2.205 (lb per liter water) ] = 108 liter/MMscf
= 28.5 gal/ MMscf
For 20 MMscfd, methanol injection will be 570 GPD (13.6 bbl/d).

Example 4-11—100 MMscf/d of natural gas leaves an offshore platform at 100°F and 1200 psia. The gas comes onshore at 40°F and 900 psia. The hydrate temperature of the gas is 65°F. Associated condensate production is 10 bbl/MMscf. The condensate has an API gravity of 50 and a MW of 140. Calculate the amount of methanol and 80 wt% EG inhibitor required to prevent hydrate formation in the pipeline.

Solution Steps:
1. Calculate the amount of water condensed per day from McKetta-Wehe (Figure 4-8),
Win =53.0 lb /MMscf
Wout = 9.5 lb/MMscf
ΔW = 43.5 lb/MMscf
Water condensed = (100)( 43.5) = 4350 lb/day
The required dewpoint depression is 65 0F– 40 0F = 25 0F
2. Calculate required methanol inhibitor concentration from Eq 4-14 and 4-17.
ΔT = KWR / M (100-WR) Eq. 4- 14

25 0F = 2335 WR / 32 (100 – WR)
WR = 25% = 0.25

Using equation 4-17
ΔT 0F =−129.6 ln (zH2O) Eq 4-17
zH2O = 0.825 , i.e. zI = (1- 0.725 )= 0.175
From WR = (MI X zI ) / (MI X zI + 18 X zH2O) Eq.4-18
WR = (0.175 X 32) / (0.175 X 32 + 0.825 X 18) = 0.275
WR = 0.275, (use this value in subsequent calculations)
3. Calculate mass rate of inhibitor in water phase
Amount of inhibitor for water phase for each lb/MMscf
mI (lb)= WR X lbH2O/MMscf /(1- WR) Eq. 4-15
= 0.275 X 43.5 /(1-0.275) = 16.5 lb/MMscf = 1650 lb/day
4. Estimate vaporization losses from Fig. 4-36. @ 40°F and 900 psia, losses = 1.05 lb/MMscf
wt% MeOH
daily losses = (1.05)(100)(27.5) = 2890 lb/day
5. Estimate losses to hydrocarbon liquid phase from Fig.4-37. @ 40°F and 27.5 wt% MeOH, approximately = 0.2 mol% lb • mols of condensate per day– “note mole% not weight %”
6. A barrel of our condensate weighs: (API =50, i.e., Sp.Gr = 0.7796), molecular weight =140.
lb.Mole per day = 100 MMscfd X 10 bbl/MMscf X [0.7796 x 2.205 (lb per liter water) x 159 (liter per barrel)] /140 = = 1950 lb−mols/day.
7. lb • mols methanol = (1950)(0.002) = 3.9 lb • mols/day
lb methanol = (3.9)(32) = 125 lb/day
Total methanol injection rate = 1650 + 2890 + 125 = 4665 lb/day
Since the specific gravity of methanol is 0.791 (at 68 0F), this is equivalent to:
4665 / [0.791 x 2.205 (lb per liter water) ] = 2674 liter/day
= 26.74 Liter/ MMscf

Methanol left in the gas phase can be recovered by condensation with the remaining water in downstream chilling processes. Likewise, the methanol in the condensate phase can be recovered by water by downstream water washing.

80 wt% EG
1. Calculate required inhibitor concentration from Eq 4-14.
ΔT = KWR / M (100-WR) Eq. 4- 14

25 0F = 2335 WR / 62 (100 – WR)
W = 40% = 0.4

2. Calculate mass rate of inhibitor in water phase from Eq.4-16.

mI = WR X mH2O / (WL − WR) Eq 4-16

mI =0.4 X 4350 / (0.8 -0.4) = 4350 lb/day

Vaporization and liquid hydrocarbon losses are negligible.
Inhibitor losses represent a significant operating cost and can cause problems in downstream process units. Efficient inhibitor separation should be provided.

4.6.4 Low Dosage Hydrate Inhibitors (LDHIs)
LDHIs can provide significant benefits compared to thermodynamic inhibitors including:
1- Significantly lower inhibitor concentrations and therefore dosage rates. Concentrations range from 0.1 to 1.0 weight percent polymer in the free water phase, whereas alcohols can be as high as 50%
2- Lower inhibitor loss caused by evaporation, particularly compared to methanol
3- Reduced capital expenses through decreased chemical storage and injection rate requirements; and no need for regeneration because the chemicals are not currently recovered.
4- These are especially appropriate for offshore where weight and space are critical to costs
5- Reduced operating expenses in many cases through decreased chemical consumption and delivery frequency
6- Increased production rates, where inhibitor injection capacity or flowline capacity is limited
7- Lower toxicity Kinetic Hydrate Inhibitors
KHIs were designed to inhibit hydrate formation in flowlines, pipelines, and downhole equipment operating within hydrate-forming conditions such as subsea and cold-weather environments. Their unique chemical structure significantly reduces the rate of nucleation and hydrate growth during conditions thermodynamically favorable for hydrate formation, without altering the thermodynamic hydrate formation conditions (i.e., temperature and pressure). This mechanism differs from methanol or glycol, which depress the thermodynamic hydrate formation temperature so that a flowline operates outside hydrate-forming conditions.

KHIs Compared to Methanol or Glycols
KHIs inhibit hydrate formation at a concentration range of 0.1–1.0 weight percent polymer in the free water phase. At the maximum recommended dosage, the current inhibition capabilities are 28°F of subcooling in a gas system and 20°F in an oil system with efforts continuing to expand the region of effectiveness.
For relative comparison, methanol or glycol typically may be required at concentrations ranging 20 to 50 weight percent respectively in the water phase.

KHI Screening Considerations
Although KHIs are applicable under most producing conditions, certain conditions must be considered when evaluating a potential application, which include water salinity, freezing conditions, hold time (i.e., period of effectiveness), water saturation, and high temperature processes.
• At water salinity levels greater than approximately 17% NaCL, the polymer may come out of solution, thereby reducing KHI effectiveness.
• A solution of KHI in water does not provide protection from freezing or icing conditions, neither in the line being treated nor in the KHI storage tank. If ambient temperatures are expected to fall below freezing, the KHI storage volume must be freeze-protected through the use of insulation on the container and piping or addition of antifreeze (typically ethylene glycol) to the KHI solution.
• A solution of KHI cannot be used for melting ice or hydrate plugs. It is recommended to have other strategies, such as a small quantity of ethylene glycol or methanol for remediation purposes in the event of a blockage.
• The KHI delivery system must be capable of providing sufficient dosage to achieve a hold time greater than the water residence time in the piping. Factors to consider include:
— The design basis duration of hydrate forming conditions for an unplanned shut-in.
— The potential for water to pool in low sections of piping (e.g., turn-down hydraulics, flowline profile, pigging frequency, flowline interconnects that are not used continuously) and dead legs.
— The seasonal duration of the cold point temperature below hydrate temperature, if applicable.
• If the gas is undersaturated with respect to water, the water in the KHI solution will evaporate and leave a high viscosity fluid. This can be addressed by using a more dilute KHI solution, or by changing the KHI carrier fluid to ethylene glycol.
• The KHI and water from the KHI solution will form separate phases if the inhibited fluid is above the lower critical solution temperature (LCST) of the KHI solution.
• The KHI polymer suffers degradation effects at temperatures above 480°F. Antiagglomerant Inhibitors
Antiagglomerants were developed out of the necessity to extend the range of subcooling for LDHIs beyond that of KHIs, and AAs can achieve subcooling of greater than 40°F. Unlike KHIs, which delay the formation of hydrates, AAs allow their formation at normal rates, but as small nonagglomerating hydrate crystals that are dispersed into an oil or condensate preventing the formation and accumulation of large hydrate crystals. Thus, AAs are suitable only in the presence of liquid hydrocarbon. The mechanism of dispersion is emulsification with the AAs acting as emulsification agents.

AAs Compared to Methanol or Glycols
The comparisons of AAs are similar for KHIs except AAs achieve greater subcooling.

AA Screening Considerations
Although AAs are applicable under most producing conditions, certain conditions must be considered when evaluating a potential application.
These conditions include water salinity, emulsification and de-mulsification (i.e., separation), pipeline hydraulics, water cuts, material compatibility, water treating, and downstream impacts.
• Some AAs have a maximum salinity criterion that is normally not exceeded with produced water.
• Since AAs are based on dispersing (i.d., emulsifying) polar hydrate crystals in a nonpolar oil or condensate phase (i.e., continuous phase), they may sometimes require a de-emulsifier for oil and water separation. Further, the addition of a heater upstream or heat coil inside a separator may be required to melt the hydrate crystals.
• Since AAs form crystals that are then dispersed in the liquid hydrocarbon phase, careful consideration of the potential impact on viscosity should be considered including steady state flow, shut-in flow and restart conditions.
• An additional consideration for AAs is that the water cuts (i.e., percent water in the liquids) should be less than 50%. Higher water cuts can invert the emulsion (i.e., change the continuous liquid phase from liquid hydrocarbon to water) and make the AA ineffective.
• AAs can impact the performance of some metallurgy and elastomers, so impacts on existing hardware should be reviewed.
• AAs typically partition (i.e., disperse) to the liquid hydrocarbon phase, but low residuals can remain in the produced water, which can impact toxicity test results.
Residual AA concentration in the hydrocarbon liquid phase could possibly impact downstream processes and should be considered in the context of overall contribution to a total feed-stream.
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