Table 2 Gas and Liquid Compositions on Platform
CALCULATION WORKSHEET
Water in hot gas 626.2 lb/MMSCF MEG Injection Rate 190.0 gal/day
Water in cold gas 6.5 lb/MMSCF (pure MEG)
WATER CONDENSED 619.8 lb/MMSCF MEG Rate/MMSCF 59.4 gal/MMSCF
Total Water CONDENSED 1983 lb/day in the line 5.7 bbl H2O/day Total water (from above) 5.9 bbl H2O/day Hydrate temperature of gas 65.0 F
Freeze depression required 27.0 F
Wt. percent methanol 27.0 % Summary of Results needed in water phase
wt. percent MEG 45.6 % needed in water phase
Vapor to liquid 0.9162 lb/MMSCFper composition ratio % in water
Methanol in gas 24.77 lb/MMSCF MEG in gas 0 lb/MMSCF
Methanol into condensate 37.5 lb/day MEG into condensate 22.5 lb/day Methanol to protect 767 lb/day water phase
MEG to protect 1735 lb/day water phase
TOTALS
Methanol to protect 767 lb/day MEG to protect 1735 lb/day water phase water phase
Methanol going to gas 79 lb/day MEG in gas 0 lb/MMSCF Methanol into condensate 37.5 lb/day MEG into condensate 22.5 lb/day
TOTAL Methanol Rate 884 lb/day TOTAL MEG Rate 1758 lb/day
Methanol Injection Rate 134.9 gal/day MEG Injection Rate 190.0 gal/day
(pure MeOH @ 77F) (pure MEG)
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the exception of gas gravity. Gas gravity was calculated using the method described in Example 4 to be 0.784. Figure 13 on the next page displays all input data and results.
The amount of methanol injected is 42.2 gal/MMscf and the amount of glycol injected is 59.4 gal/MMscf.
_____________________________________________________________________ For ease of use, the engineer will turn to HYDCALC to perform the second approximation calculation. The following section provides accuracy and limitations of both HYDCALC and the hand calculation methods, which are vital to their use.
II.C.6. Accuracy, Limitations, and Extensions for Second Estimation Method A comparison of the previous results using the hand calculation method and the HYDCALC method is included in the below table.
Calculated Quantity Hand Method Result with Rules-of-Thumb HYDCALC Result Water Condensed, lbm/MMscf 591 619.8 MeOH in Water, lbm/MMscf 228.7 239.7 MeOH in Gas, lbm/MMscf 27 24.7 MeOH in Condensate, lbm/MMscf 11.7 11.7
Total MeOH Injection, lbm/MMscf 267.4 276.25
Total MeOH Injection, gal/MMscf 40.3 42.2
While the hand calculation and the computer program provide only slightly different results, both include inaccuracies. For example, while it is possible to obtain more significant figures with HYDCALC than with the charts in the hand method, HYDCALC inaccuracies are those of the charts upon which HYDCALC is based.
Using HYDCALC it was estimated that 27 wt% methanol was required in the water phase to inhibit the pipeline, while measurements by Robinson and Ng (1986) show that only 20 wt% methanol was required for inhibition at the same gas composition, temperature, and pressure of Examples 6 and 7.
The major inaccuracies in the second estimation method are in the gas gravity hydrate formation conditions, which are only accurate to ±7oF or to ±500 psia. The Hammerschmidt equation, the inhibitor temperature depression ∆T is accurate to ± 5%. With such inaccuracies, the amount of methanol or glycol injection could be in error by 100% or more. The principal virtue of the second estimation method is ease of calculation rather than accuracy.
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A second limitation is that the method was generated for gases without H2S,
which represents the case for many gases in the Gulf of Mexico. A modification of the gas gravity method was proposed for sour gases by Baillie and Wichert (1987).
II.D. Most Accurate Calculation of Hydrate Formation and Inhibition.
If the HYDCALC results indicate that hydrate formation will occur without inhibition, the engineer should elect to do further, more accurate calculations. The most accurate method for hydrate formation conditions, together with the amount of methanol needed in the water phase, is available as the final estimation technique in a computer program, HYDOFF. A User’s Manual (Appendix B) and an example are provided with this handbook. The method details are too lengthy to include here; the engineer interested in program details is referred to the hydrate text by Sloan (1998, Chapter 5).
In Section II.D examples are provided for the most accurate methods for the following calculations:
• calculation of hydrate formation and inhibition in water (Section II.D.1),
• conversion of MeOH to MEG concentration in water phase (Section II.D.2),
• calculation of solubility of MeOH and MEG in the gas (Section II.D.3), and
• calculation of solubility of MeOH and MEG in condensate (Section II.D.4).
II.D.1. Hydrate Formation and Inhibitor Amounts in Water Phase. HYDOFF is an IBM-compatible computer program provided on the disk with this handbook. The program enables the user to determine hydrate formation conditions and the amount of inhibitor needed in the free water phase. As a minimum of a 386-IBM computer with 2 megabytes of RAM is required. The program may be executed either from the Windows or from the DOS environment.
To use the program, first load both HYDOFF.EXE and FEED.DAT from the accompanying 3.5 inch disk onto a hard drive. Appendix B is a User’s Manual with several examples of the use of HYDOFF. The simplest (and perhaps the most beneficial) use of HYDOFF is illustrated through Example 8.
_____________________________________________________________________ Example 8: Use of HYDOFF to Obtain Hydrate Formation and Prevention Conditions. Find (a) the hydrate formation pressure of the below natural gas at 38oF and (b) the amount of methanol in the water phase to inhibit hydrates at 38oF and 1000 psia. The
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gas composition (mole %) is: methane = 71.60%, ethane = 4.73%, propane = 1.94%, n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen = 5.96% Solution: The gas in this example has the same composition as the gas in Examples 6 and 7, so the results provide a comparison with hand and computer calculations of the gas gravity method (Section II.C.1) and the Hammerschmidt equation (Section II.C.2).
For convenience with multiple calculations, the reader may wish to edit the program FEED.DAT to reflect the gas composition of the problem. Modification of the FEED.DAT program is done at the MSDOS prompt, by changing the composition of each component to that of the example gas, and saving the result using the standard MSDOS editing technique. However it is not necessary to use FEED.DAT; the gas composition may be input as part of the program HYDOFF.
In the following solution, each input from the user is underlined:
1. From Windows or in the proper directory, click on, or type HYDOFF; press Enter. 2. After reading the title screen, press Enter
3. At the “Units” screen, press 1 (to choose oF and psia) then Enter
4. At the FEED.DAT question screen, press 2 and Enter if you wish to use the data in FEED.DAT, or 1 and Enter if you wish to enter the gas composition in HYDOFF by hand. The remainder of this example is written assuming that the user will enter the gas composition in HYDOFF rather than use FEED.DAT. The use of FEED.DAT is simpler and should be considered for multiple calculations with the same gas.
5. The next screen asks for the number of components present (excluding water). Input 7 and Enter.
6. The next screen requests a list of the gas components present, coded by numbers shown on the screen. Input 1, 2, 3, 5, 7, 8, and 9 (in that order, separating the entries by commas) and then Enter.
7. The next series of screens request the input of the mole fractions of each component Methane 0.7160 Enter.
Ethane 0.0473 Enter. Propane 0.0194 Enter. n-Butane 0.0079 Enter. Nitrogen 0.0596 Enter. Carbon Dioxide 0.1419 Enter. n-Pentane 0.0079 Enter. 8. At the “Options” screen, input 1 then Enter.
9. At the screen asking for the required Temperature, input 38, and Enter.
10. Read the hydrate formation pressure of 229.7 psia, (meaning hydrates will form at any pressure above 230 psia at 38oF for this gas.)
11. When asked for another calculation input 1 for “No” then Enter. 12. At the “Options” screen input 2, then Enter.
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13. At the screen asking for the required temperature, input 38, and Enter. 14. At the screen to enter the “WEIGHT PERCENT of Methanol,” input 22. 15. Read the resulting hydrate condition of 22 wt% MeOH, 38oF, and 1036 psia.
It may require some trial and error with the use of the program before the correct amount of MeOH is input to inhibit the system at the temperature and pressure of the example. One starting place for the trial and error process would be the amount of MeOH predicted by the Hammerschmidt equation (27 wt%) in Example 6. Ng and Robinson (1983) measured 20 wt% of methanol in the water required to inhibit hydrates at 38oF and 1000 psia. A comparison of the measured value with the calculated value (22 wt%) in this example and through the Hammerschmidt equation provides an indication of both the absolute and relative calculation accuracy.
HYDOFF can also be used to predict the uninhibited hydrate formation temperature at 1000 psia at 58.5oF, through a similar trial and error process, as compared with 65oF determined by the gas gravity method. No measurements are available for the uninhibited formation conditions of the gas in this example.
In using HYDOFF, if components heavier than n-decane (C10H22) are present,
they should be lumped with n-decane, since they are all non-hydrate formers.
_____________________________________________________________________
II.D.2 Conversion of MeOH to MEG Concentration in Water Phase. The concentration of inhibiting monoethylene glycol (MEG) in the water phase can be determined from methanol (MeOH) concentration using a simple correlation of inhibitors:
wt% MEG = -1.209+ 2.34 (wt% MeOH)- 0.052(wt% MeOH)2+ 0.0008(wt% MeOH)3 (2) In order to use Equation (2), first determine the amount of methanol required using HYDOFF, as in Example 8. Insert the amount of methanol in Equation (2) to determine the amount of mono-ethylene glycol needed in water to inhibit hydrates. Equation (2) should be used for the free water phase only. Example 9 (Section II.D.5) provides a summary calculation of all the procedures in Section II.D.
II.D.3. Solubility of MeOH and MEG in the Gas. Figure 11 is a fit of recent measurements by Ng and Chen (1995) for KvMeOH defined as the methanol mole
fraction in gas relative to water (≡ yMeOH/xMeOH in H2O). Once the mole fraction of
methanol in water is determined, it may be multiplied by KvMeOH to obtain the mole
fraction of methanol in the gas. As can be determined by Figure 11, the solubility in the water is only slightly affected by pressure over the range from 1000-3000 psia at offshore temperatures. For a conservative estimate the 3000 psia line is recommended:
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KvMeOH = exp (5.706 - 5738×(1/T(oR)) (3)
Figure 12 provides an estimation of monoethylene glycol dissolved in gas at 1000 psig, from the data of Polderman (1958). As indicated in the figure the amount of MEG in the vapor is very small; Ng and Chen (1995) measure a negligible MEG concentration in the vapor as a comparison. Example 9 (Section II.D.5) provides a summary calculation of all the procedures in Section II.D.
II.D.4. Solubility of MeOH and MEG in the Condensate. Figure 14 is a fit of measurements by Ng and Chen (1995) for KLMeOH defined as the methanol mole
fraction in condensate relative to water (≡ xMeOH in HC/xMeOH in H2O). Once the mole
fraction of methanol in water is determined, it may be multiplied by KLMeOH to obtain
the mole fraction of methanol in the condensate. In Figure 14 all lines are pressure independent and the toluene line should not apply, due to the absence of such compounds in typical condensates. The fit for the solubility of methanol in condensates of methane, propane, and n-heptane is recommended:
KLMeOH = exp (5.90 - 5404.5×(1/T( o
R)) (4) Similar measurements by Ng and Chen (1995) are shown in Figure 15 to specify the solubility for monoethylene glycol (MEG) in the condensate, via KLMEG
defined as the MEG mole fraction in condensate relative to water (≡ xMEG in HC/xMEG in H2O). Note that the KLMEG values are two orders of magnitude lower than KLMeOH
values. No pressure dependence is observed, and the line for MEG solubility in methane, propane, and n-heptane (or methylcyclohexane) is recommended, since toluene is not in condensate:
KLMEG = exp (4.20 - 7266.4×(1/T(oR)) (5)
Example 9 (Section II.D.5) provides a summary calculation of all the procedures in Section II.D.
II.D.5. Best Calculation Technique for MeOH or MEG Injection. The following example is identical that of Examples 6 and 7, with the exception that both MeOH and MEG injection are calculated for comparison of each inhibitor as well as with the less accurate method of Section II.C.
_____________________________________________________________________ Example 9: Most Accurate Inhibitor Injection Calculation. A sub-sea pipeline with the below gas composition has inlet pipeline conditions of 195oF and 1050 psia. The
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gas flowing through the pipeline is cooled by the surrounding water to a temperature of 38oF. The gas also experiences a pressure drop to 950 psia. Gas exits the pipeline at a rate of 3.2 MMscf/d. The pipeline produces condensate at a rate of 25 bbl/d, with an average density of 300 lbm/bbl and an average molecular weight of 90 lbm/lbmole. Produced salt-free water enters the pipeline at a rate of 0.25 bbl/d.
Natural gas composition (mole%): methane = 71.60%, ethane = 4.73%, propane = 1.94%, n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen = 5.96%
Find the rate of both methanol and monoethylene glycol injection needed to prevent hydrate formation in the pipeline.
Solution:
Basis: the basis for solution is 1 MMscf/d.
Step 1) Calculate the Concentration of MeOH and MEG in the Water Phase.
In Example 8 the methanol concentration was calculated to be 22 wt% of the free water phase at 38oF and 1000 psia. Using Equation (2) the MEG concentration was calculated at 33.6 wt% in the water phase.
Step 2) Calculate the Mass of Liquid H2O/MMscf of Natural Gas
- Calculate Mass of Condensed H2O
Use the water content chart (Figure 10), to calculate the water in the vapor/MMscf. The inlet gas (at 1050 psia and 195oF) water content is read as 600 lbm/MMscf. The outlet gas (at 950 psia and 38oF) water content is read as 9 lbm/MMscf. The mass of liquid water due to condensation is:
600 lbm _ 9 lbm = 591 lbm MMscf MMscf MMscf
- Calculate Mass of Produced H2O Flowing into the Line
Convert the produced water of 0.25 bbl/d to the basis of lbm/MMscf:
- Total Mass of Water/MMscf Gas: Sum the condensed and produced water 591 lbm + 27.4 lbm = 618.4 lbm MMscf MMscf MMscf MMscf O H lb MMscf day gal lb bbl gal day O bblH2 m m 2 4 . 27 2 . 3 1 34 . 8 42 25 . 0 =
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Step 4) Calculate the Rate of Methanol and MEG Injection
MeOH and MEG can exist in three phases: water, gas, and condensate. The total masses of MeOH and MEG injected per MMscf are calculated as follows:
-Calculate Amount of (a) MeOH and (b) MEG in the Water Phase
(a) 22.0 wt% methanol is required to inhibit the free water phase, and the mass of water/MMscf was calculated at 618.4 lbm. The mass of MeOH in the free water phase per MMscf is:
22wt% M lb MeOH M lb MeOH 618.4lb H O m m m 2 = + ×100%
Solving M = 174.4 lbm MeOH/MMscf in the water phase
(b) In Step 1 33.6.0 wt% MEG is required to inhibit the free water phase, and the mass of water/MMscf was calculated at 618.4 lbm in Step 3. The mass of MEG in the free water phase per MMscf is:
33.6wt% N lb MEG N lb MEG 618.4lb H O m m m 2 = + ×100%
Solving N = 313.1 lbm MEG/MMscf in the water phase
-Calculate Amount of (a) MeOH and (b) MEG Lost to the Gas
(a) MeOH Lost to Gas. The mole fraction MeOH in the free water phase is:
mole fraction MeOH = 174.4 lb MeOH lb lbmol MeOH) 174.4 / 32 + 618.4lb H O / (18lb / lbmolH O)
m m
m 2 m 2
/ (32 /
The mole fraction MeOH in the water phase is xMeOH in H2O = 0.137. The distribution constant of MeOH in the gas is calculated at 38oF (497.7oR) by Equation (3), relative to the methanol in the water
KvMeOH = exp (5.706 - 5738×(1/497.7oR) = 0.00296 (3)
where oR = oF + 459.69
The mole fraction of MeOH in the vapor is yMeOH = KvMeOH•xMeOH in H2O or yMeOH = 0.00296 × 0.137 = 0.0004055
The daily gas rate is 8432 lbmol (= 3.2 × 106 scf / (379.5 scf/lbmol), where an scf is at 14.7 psia and 60oF), so that the MeOH lost to the gas is 3.42 lbmol (=
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0.0004055 × 8432) or 109.4 lbm/day. Since the calculation basis is 1 MMscf/d, the amount of MeOH lost is 34.2 lbm/MMscf (= 109.4 lbm / 3.2 MMscf).
(b) MEG Lost to Gas. In Figure 12 use the 50 wt% MEG line to determine the MEG lost to the gas is 0.006 lbm/MMscf at 38oF and 1000 psig; such an amount is negligible. Ng and Chen (1995) measured a negligible concentration of MEG in the gas phase at conditions similar to those of this problem.
-Calculate Amount of (a) MeOH and (b) MEG Lost to the Condensate
(a) MeOH lost to the condensate. The distribution of MeOH in the condensate is calculated via equation (4)
KLMeOH = exp (5.90 - 5404.5×(1/497.7oR)) = 0.00702 (4)
where oR = oF + 459.69.
The mole fraction MeOH in condensate is xMeOH in HC = KLMeOH×xMeOH in H2O or xMeOH in HC = 0.00702 × 0.137 = 0.0009617
The condensate rate is 26.0 lbmoles/MMscf (= 25bbl/d×300 lbm/bbl×1 lbmol/90 lbm×1d/3.2 MMscf) so that the amount of MeOH in condensate is 0.025 lbmol/MMscf (= 0.0009617 × 26 / ( 1 - 0.009617)) or 0.8 lbm/MMscf) (b) MEG Lost to Condensate. The mole fraction MEG in the water phase is calculated as
mole fraction MEG = 313.1 lb MEG lb lbmol MEG) 313.1 / 62 + 618.4lb H O / (18lb / lbmolH O)
m m
m 2 m 2
/ (62 /
The mole fraction MEG in the water phase is xMEG in H2O = 0.128.
The distribution of MEG between the aqueous liquid and condensate is given by
KLMEG = exp (4.20 - 7266.4×(1/497.7 oR)) = 3.04 × 10-5 (5) The mole fraction MEG in condensate is xMEG in HC = KLMEG×xMEG in H2O calculated as 3.8 × 10-6.(= 3.04 × 10-5 × 0.128). The condensate rate is 26.0 lbmoles/MMscf (= 25bbl/d×300 lbm/bbl×1 lbmol/90 lbm×1d/3.2 MMscf) so that the amount of MEG in condensate is 9.9×10-5 lbmol/MMscf (= 0.0000038
× 26 / ( 1 - 0.0000038)) or 0.0061 lbm/MMscf)
30 MeOH MEG In Water, lbm/MMscf 174.4 313.1 In Gas, lbm/MMscf 34.2 0.006 In Condensate, lbm/MMscf 0.8 0.0061 Total, lbm/MMscf 209.4 313.11 Total, gal/MMscf 31.5 33.3
The example illustrates that for this gas condition, the injection amounts of MeOH and MEG are comparable. The more precise calculation shown here however, represents a considerable savings in the amount of MeOH injected (31.5 gal/MMscf versus 42.2 gal/MMscf in the second estimation method.)
_____________________________________________________________________
II.E. Case Study 6: Prevention of Hydrates in Dog Lake Field Pipeline
As a summary of the thermodynamic hydrate prevention methods, consider the steps taken to prohibit hydrates in the Dog Lake Field export pipeline in Louisiana, by Todd et al., (1996) of Texaco. During the winter months hydrates formed in the line. While this pipeline passes through shallow water (a marsh) many of the principles illustrate applications to offshore pipeline design.
Hydrate formation conditions, shown in Figure 16, are calculated via an earlier version of HYDOFF with 0 wt%, 10%, and 20% methanol in the water phase. The Dog Lake gas composition is: 92.1 mole% methane, 3.68% ethane, 1.732% propane, 0.452% i-butane, 0.452% n-butane, 0.177% i-pentane, 0.114% n-pentane, 0.112% hexane, 0.051% heptane, 0.029% octane, 0.517% nitrogen, 0.574% carbon dioxide.
The pipeline pressure and temperature, calculated using PIPEPHASE , were superimposed on the hydrate formation curve shown in Figure 17. Gas leaves the wellhead at 1000 psia and 85oF, far from hydrate forming conditions. As the gas moves down the pipeline, it begins to cool towards ambient temperatures. Once the temperature reaches approximately 63oF hydrates will form, so methanol must be added. The figure shows pipeline conditions and the hydrate formation curves for various concentrations of methanol, indicating that 25% wt% methanol in water is needed to inhibit hydrates.
Despite large quantities of methanol injection for hydrate prevention, 110 hydrate incidents occurred in the line during winter of 1995-1996 at a cost of $323,732. Combinations of four alternative hydrate prevention methods were considered: (1) burying the pipeline, (2) heating the gas at the wellhead, (3) insulating the pipeline, and (4) methanol addition. The details of each prevention measure are considered below.