-
Note: The source of the technical material in this volume is the
Professional Engineering Development Program (PEDP) of Engineering
Services.
Warning: The material contained in this document was developed
for Saudi Aramco and is intended for the exclusive use of Saudi
Aramcos employees. Any material contained in this document which is
not already in the public domain may not be copied, reproduced,
sold, given, or disclosed to third parties, or otherwise used in
whole, or in part, without the written permission of the Vice
President, Engineering Services, Saudi Aramco.
Chapter : Chemical For additional information on this subject,
contact File Reference: CHE-206.02 PEDD Coordinator on 874-6556
Engineering Encyclopedia Saudi Aramco DeskTop Standards
HYDRATE INHIBITION METHODS
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards i
CONTENT PAGE
INTRODUCTION...........................................................................................................................8
TEMPERATURE CONTROL METHODS AND EQUIPMENT USED TO INHIBIT
HYDRATE FORMATION IN A NATURAL GAS
STREAM......................9
Downhole
Regulators.....................................................................................................10
Downhole Regulator
Design.............................................................................10
Indirect Heaters
..............................................................................................................11
Indirect Heater
Design.......................................................................................11
Indirect Heater
Sizing.........................................................................................13
Advantages and Disadvantages of Temperature Control
Methods.........................14
Downhole
Regulators.........................................................................................14
Indirect Heaters
..................................................................................................15
Comparison of Temperature Control
Methods...............................................15
CALCULATING METHANOL INJECTION RATE REQUIRED TO INHIBIT HYDRATE
FORMATION IN A NATURAL GAS
STREAM.................................17
Chemical
Injection..........................................................................................................17
Equation for Calculating Required Depressions of
Hydrate-Formation
Temperatures................................................................17
Hammerschmidt
Equation.................................................................................18
Methanol..........................................................................................................................19
Methanol Applications
.......................................................................................21
Methanol Injection
System.................................................................................22
Hammerschmidt Equation Modified for High Concentrations of
Methanol................................................................25
Determining Methanol Injection Rates (General
Applications)..................................26
Calculating Water Content of Gas Stream
(W)...............................................27
Determining Hydrate-Formation Temperature
(TH).......................................27
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards ii
Calculating Methanol Concentration Required to Depress
Hydrate-Formation
Temperature.................................................28
Calculating Methanol Injection Rates (q MeOH)
.............................................28
Calculating Methanol Injection Rates (Cryogenic
Applications)................................31
Determining Water Content
..............................................................................32
Determining Hydrate-Formation
Temperature................................................32
Calculating Required Depression of Hydrate-Formation Temperature
.......32
Determining Solubility of Methanol in
Hydrocarbons......................................34
Calculating Methanol Injection Rates
...............................................................34
CALCULATING GLYCOL INJECTION RATE REQUIRED TO INHIBIT HYDRATE
FORMATION IN A NATURAL GAS
STREAM.................................41
Glycol Concentration and
Dilution................................................................................43
Selecting Glycol Type
....................................................................................................45
Glycol Injection and Recovery System
.........................................................................46
Glycol Injection and Recovery System Using Two
Separators......................46
Glycol Injection and Recovery System Using a Three-Phase
Separator
......................................................................48
Glycol Injection and Recovery System
Components..................................................50
Separators
..........................................................................................................50
Reboiler...............................................................................................................50
Inhibitor
Pump.....................................................................................................52
Glycol Losses
.....................................................................................................52
Nozzle Selection and
Placement......................................................................52
Calculating Glycol Injection
Rates.................................................................................56
Water Content, Hydrate-Formation Temperature, and Safety Margin
.........57
Concentration of
Glycol......................................................................................57
Effects of Dilution Restrictions on Calculating Glycol
Concentrations..........58
Calculating Glycol Injection Rates: Graphical
Method...................................62
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards iii
SUMMARY..................................................................................................................................65
Temperature Control
Methods......................................................................................65
Chemical
Injection..........................................................................................................65
Methanol..............................................................................................................66
Glycol...................................................................................................................66
Calculating Inhibitor Injection Rates
Summary............................................................68
WORK AID 1: PROCEDURES AND RESOURCES FOR CALCULATING METHANOL
INJECTION RATE REQUIRED TO INHIBIT HYDRATE FORMATION IN A NATURAL
GAS STREAM..........................69
Work Aid 1A: Procedures and Resources for Calculating Methanol
Injection Rates (General
Applications).............................69
Required Depression of Hydrate-Formation Temperatures
.........................69
Hammerschmidt
Equation.................................................................................69
Hammerschmidt Equation (Eqn. 3) Solved for the Weight Percent of
Inhibitor
.......................................................70
Free Water Condensed Out of Gas Stream
...................................................70
Methanol Injection Rate Required to Compensate for Vapor
Losses..........71
Methanol Injection Rate Required to Achieve Aqueous Methanol
Concentration.................................................71
Total Methanol Injection Rate
............................................................................71
Work Aid 1B: Procedures and Resources for Calculating Methanol
Injection Rates (Cryogenic Applications)
..........................76
Depression Of Hydrate-Formation
Temperatures......................................................76
Hammerschmidt Equation Modified for High Concentrations of
Methanol................................................................76
Flow Rate of Free Water
...................................................................................77
Depressed Hydrate-Formation Temperature
(THdepressed)......................78
Safety
Margin......................................................................................................78
Methanol Injection Rate: Vapor
Losses...........................................................78
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards iv
Methanol Injection Rate: Solubility in Hydrocarbon
Liquid.............................79
Methanol Injection Rate Required to Achieve Aqueous Methanol
Concentration.................................................79
Total Methanol Injection Rate
(Cryogenic).......................................................79
Methanol Injection Rate Converted to
gpm......................................................80
WORK AID 2: PROCEDURES AND RESOURCES FOR CALCULATING GLYCOL
INJECTION RATE REQUIRED TO INHIBIT HYDRATE FORMATION IN A NATURAL
GAS STREAM..........................89
Depression Of Hydrate-Formation Temperatures (Thermodynamic)
..........89
Hammerschmidt
Equation.................................................................................90
Hammerschmidt Equation (Eqn. 3) Solved for the Weight Percent of
Inhibitor
.......................................................90
Free Water Condensed Out of Gas Stream
...................................................90
Flow Rate of Free Water, q water (Glycol Injection Rate
Calculations)........91
Rich Glycol Concentration Required to Meet Dilution Restrictions
(w
richdilution)....................................................91
Inhibitor Injection Rate (Dilution
Restricted).....................................................92
GLOSSARY.............................................................................................................................
100
ADDENDUM A: SYMBOLS FOR PHYSICAL QUANTITIES USED IN CHE
206.02..... 103
ADDENDUM B: ABBREVIATED LIST OF EQUATIONS USED IN CHE
206.02.......... 104
Depression of Hydrate-Formation Temperatures
................................................... 104
Depression of Hydrate-Formation Temperatures (Thermodynamic)
.................... 104
Hammerschmidt
Equations........................................................................................
104
Derivations of Hammerschmidt
Equations...............................................................
104
Hammerschmidt Equation (Eqn. 3) Solved for the Weight Percent of
Inhibitor ....................................................
104
Hammerschmidt Equation Modified for High Concentrations of
Inhibitor
...............................................................
104
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards v
Hammerschmidt Equation Modified for High Concentrations of
Methanol.............................................................
105
Free Water Condensed Out of Gas Stream
............................................................
105
Methanol Injection Rate (General
Applications).......................................................
105
Methanol Injection Rate Required to Compensate for Vapor
Losses....... 105
Methanol Injection Rate Required to Achieve Aqueous Methanol
Concentration.............................................. 105
Total Methanol Injection Rate
.........................................................................
105
Flow Rate of Free Water (Cryogenic Applications)
................................................ 105
Depressed Hydrate-Formation Temperature
(THdepressed)............................... 106
Safety
Margin...............................................................................................................
106
Methanol Injection Rate: Vapor Losses (Cryogenic Applications)
........................ 106
Methanol Injection Rate: Solubility in Hydrocarbon
Liquid...................................... 106
Methanol Injection Rate Required to Achieve Aqueous Methanol
Concentration..........................................................
106
Total Methanol Injection Rate
(Cryogenic)................................................................
106
Methanol Injection Rate Converted to
gpm...............................................................
106
Flow Rate of Free Water, q water (Glycol Injection Rate
Calculations)................. 106
Rich Glycol Concentration Required to Meet Dilution Restrictions
(w
richdilution)............................................................
107
Inhibitor Injection Rate (Dilution
Restricted)..............................................................
107
ADDENDUM C: INDIRECT HEATER SIZING
CALCULATIONS..................................... 108
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards vi
List of Figures
Figure 1: Typical Indirect
Heater..............................................................................................12
Figure 2: Typical Wellhead Heater
Installation.......................................................................12
Figure 3: Comparison Of Temperature Control
Methods.....................................................16
Figure 4: Effect Of Methanol On Hydrate Formation In Propane
.........................................20
Figure 5: Methanol Injection System
.......................................................................................22
Figure 6: Methanol Injection And Recovery
System..............................................................24
Figure 7: Mass Balance Around Separator
...........................................................................33
Figure 8: Flow Of Gas Stream In Methanol Injection Sample
Problem (Cryogenic)..........35
Figure 9: Mass Balance Around Separator In Methanol Injection
Sample Problem (Cryogenic)
.........................................................................................................38
Figure 10: Comparison Of Chemical Injection Inhibitors
......................................................41
Figure 11: Freezing Points Of Aqueous Glycol
Solutions.....................................................43
Figure 12: Allowable Glycol
Dilutions......................................................................................44
Figure 13: Dow Chemical Glycol Recommendations
...........................................................45
Figure 14: Glycol Injection And Recovery
System.................................................................47
Figure 15: Glycol Injection And Recovery System (Three-Phase)
.......................................49
Figure 16: Boiling Point Of
Meg..............................................................................................51
Figure 17: Glycol Sprayed Onto The Tube Sheet Of A Heat
Exchanger ............................54
Figure 18: Increase In Pressure Drop Because Of Hydrate
Formation..............................55
Figure 19: Nozzle Placed At Three Locations: One Flow
Rate...........................................55
Figure 20: Nozzle Placed At One Location: Three Flow
Rates...........................................56
Figure 21: Comparison Of Hydrate Inhibition
Methods.........................................................66
Figure 22: Comparison Of Chemical Inhibitors
.....................................................................67
Figure 30: Summary Of Method For Calculating Methanol Injection
Rates (Steps 1 To
4).....................................................................................................72
Figure 31: Summary Of Method For Calculating Methanol Injection
Rates (Steps 5 To
9).....................................................................................................73
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards vii
Figure 32: Depression Of Hydrate-Formation Temperatures, ?T
(Methanol) ..................74
Figure 33: Methanol Vapor-To-Liquid Composition Ratios
.................................................75
Figure 34: Summary Of Calculating Methanol Injection Rate For
Cryogenic Applications (Steps 1 To
4).....................................................81
Figure 35: Summary Of Calculating Methanol Injection Rate For
Cryogenic Applications (Steps 5 To
8).....................................................82
Figure 36: Summary Of Calculating Methanol Injection Rate For
Cryogenic Applications (Steps 9 To 14)
..................................................83
Figure 37: Depression Of Hydrate-Formation Temperature By
Methanol (Modified Hammerschmidt Equation)
.............................................................84
Figure 38: Solubility Of Methanol In Hydrocarbon Vapor (65F To
-20F)..........................84
Figure 39: Solubility Of Methanol In Hydrocarbon Vapor (-20F To
-120F)......................85
Figure 40: Solubility Of Methanol In Hydrocarbon Vapor (-125F To
-175F)....................85
Figure 41: Solubility Of Methanol In Hydrocarbon
Liquid......................................................86
Figure 42: Density Of Aqueous Methanol
Solutions..............................................................87
Figure 43: Water Content (W) Of Natural Gas At Low
Temperatures.................................88
Figure 44: Calculating Glycol Injection Rates (Steps 1 To 6)
...............................................93
Figure 45: Calculating Glycol Injection Rates (Steps 7 To
11).............................................94
Figure 46: Physical Properties Of Hydrate Inhibitors
............................................................95
Figure 47: Allowable Glycol
Dilutions......................................................................................96
Figure 48: Freezing Points Of Aqueous Glycol
Solutions.....................................................96
Figure 49: Density Of Meg Solutions
......................................................................................97
Figure 50: Depression Of Hydrate-Formation Temperature (MEG)
...................................98
Figure 51: MEG Injection
Rate.................................................................................................99
Figure 52: Symbols Used In Che 206.02
............................................................................
103
Figure 53: Coil Size
Selection..............................................................................................
110
Figure 54: Heater-Coil Transfer
Coefficients......................................................................
110
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 8
INTRODUCTION
The previous module, ChE 206.01, covered predicting hydrate
formation. This module covers the following methods of preventing,
or inhibiting, the formation of hydrates.
Temperature control
Methanol injection
Glycol injection
This module first covers the inhibition hydrate formation by
means of indirect heaters and downhole regulators to control gas
stream temperatures. The module then discusses the calculation of
methanol injection rates that are required to inhibit hydrate
formation for both general and cryogenic applications. Finally, the
module discusses the calculation of injection rates, including the
use of graphical methods.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 9
TEMPERATURE CONTROL METHODS AND EQUIPMENT USED TO INHIBIT
HYDRATE FORMATION IN A NATURAL GAS STREAM
Heating a natural gas or depressurizing it (thus cooling it)
while it is under hot conditions can inhibit hydrate formation. In
above ground operations, the temperature drop caused by
depressurizing (expanding) a gas can result in the temperature of
the gas stream dropping below its hydrate-formation temperature.
Because of the high temperatures underground, a gas stream can be
expanded underground without the resulting temperature dropping
below its hydrate-formation temperature. Therefore, expanding a gas
stream in a well bore helps prevent hydrate-formation in downstream
processing.
The two main pieces of equipment used to control gas stream
temperature and inhibit hydrate formation are downhole regulators
and indirect heaters. Downhole regulators inhibit hydrate formation
by expanding gas streams while they are in the wellbore. Indirect
heaters inhibit hydrate formation both at wellheads (wellhead
heaters) and along flowlines (flowline heaters). Indirect heaters
are often used to inhibit hydrate formation caused by expansion or
to replace heat lost by a flowline to the surrounding air and
ground.
Downhole regulators and indirect heaters are used around the
world. Saudi Aramco however, does not commonly use either
temperature control method. Saudi Aramcos only gas wells, Khuff
gas, operate at a high enough temperature that hydrates are not a
problem. Saudi Aramcos gas pipelines do not use indirect heaters as
the gas in these lines has already been processed to some extent
(such as dew-point conditioning) that hydrates are not a
problem.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 10
Downhole Regulators
The use of downhole regulators to inhibit hydrate formation by
controlling gas stream temperatures is generally feasible when the
gas well has the following conditions:
A high reservoir pressure that is not expected to decline
rapidly
Excess pressure
High capacity
The temperature and pressure of a gas stream as well as its
composition determine whether hydrates will form when gas is
expanded into the flowlines. Cooling occurs as gas is expanded
across the choke. Downhole regulators lower the pressure of the gas
stream from well pressure to near-salesline pressure in the
wellbore. Operating conditions resulting from the expansion of the
gas are outside the hydrate-formation range of the gas stream
because of the high temperatures in the well.
Downhole Regulator Design
Downhole regulators contain a spring-loaded valve and stem that
outside vendors set from the surface by using a wireline (wire used
to lower tools into the wellbore) run through the wellbore tubing.
The pressure drop across the regulator remains constant and does
not depend, within a broad range, on the flow rate of the well.
The design of downhole regulators requires using complex
calculations that must account for the following:
Downhole pressures and temperatures
Well depth
Wellbore configuration
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 11
The performance of these involved calculations is not necessary
because production equipment vendors provide detailed information
on the design of downhole regulators. However, simpler calculations
estimate the feasibility of installing downhole regulators.
Indirect Heaters
Two types of indirect heaters are used to inhibit hydrate
formation: wellhead and flowline. The expansion of gas streams at
or near wellheads often results in the formation of hydrates.
Wellhead heaters keep the temperatures of these gas streams above
their hydrate-formation temperatures.
Flowlines in other parts of the world often lose enough heat to
the surrounding air and ground to lower the temperature of the gas
stream below its hydrate-formation temperature. Flowline heaters
inhibit hydrate formation by replacing this lost heat and keeping
the temperature of the gas stream above its hydrate-formation
temperature. Flowline heaters also inhibit hydrate formation by
heating gas streams expanded or choked downstream from the
wellhead.
Indirect Heater Design
Different heater designs accomplish the same purpose: to heat
the gas. Flowline heaters do not require the chokes and
high-pressure safety valves that wellhead heaters need.
Indirect heaters are vessels that contain a fire tube and a coil
immersed in a heat transfer fluid (usually water or a glycol and
water mixture) within a heater shell. The fire tube is usually
fired by gas. The coil contains the fluid (the gas stream) to be
heated and operates at full gas pressure. The heater shell operates
at atmospheric pressure. Figure 1 shows a typical indirect
heater.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 12
FIGURE 1: TYPICAL INDIRECT HEATER
Wellhead heaters - Figure 2 shows a schematic of a typical
wellhead heater.
FIGURE 2: TYPICAL WELLHEAD HEATER INSTALLATION
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 13
Flowline Heaters - Flowline heaters heat gas streams above their
hydrate-forming temperatures. In many cases, properly designed and
placed wellhead heaters provide sufficient heat to eliminate the
need for flowline heaters.
Unlike wellhead heaters, flowline heaters do not require most of
the equipment shown in Figure 2. Flowline heaters require a bypass
valve so that a heater can be removed from service or to allow the
pipeline to be scrapped.
Indirect Heater Sizing
The determination of the size of a heater depends on the
following conditions:
Amounts of gas, water, oil, or condensate expected in the
heater
Inlet temperature and pressure
Outlet temperature and pressure (to avoid hydrate-forming
conditions)
The size of heater coils to use depends on the volume of fluid
flowing through the coil and the required heat-transfer load.
When heater coils are sized, it is important to consider
operating conditions in addition to normal, steady-state operating
conditions. Transient startup of a shut-in well may require extra
heating capacity. The temperature and pressure conditions of a
shut-in well and the extra liquids accumulated while the well was
shut in may increase the heating load. Often, heaters are necessary
only while wells are being started up. Installing preheat coils
ahead of chokes is generally practical for wells operated only
intermittently.
System Optimization - Heat requirements that at first appear
large can often be reduced or even eliminated by optimizing the
operation of a gas system. For instance, the combination of gas
streams from multiple wells can produce higher gas flow
temperatures. Furthermore, the reduction of gas pressures of the
lines at a central point is generally more efficient than
separately reducing the gas pressures of the lines.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 14
However, the reduction of flowline pressures at a central point
requires extra-strength gathering lines that can withstand wellhead
shut-in pressures. The regulation of the pressure of gathering
lines by the installation of well shut-in valves eliminates the
need for extra-strength piping.
Indirect Heater Sizing Calculations - The calculations required
to size indirect heaters are complex and are not covered in detail.
The procedure for sizing an indirect heater is described below and
in Addendum C.
The need for a heater preheat coil is determined.
The outlet temperature of the heater is determined.
The heat required to heat the gas is calculated.
The size and surface area of the heating coil is determined.
Advantages and Disadvantages of Temperature Control Methods
Downhole Regulators
Downhole regulators have the following advantages:
Low initial investment
Do not require routine service
Downhole regulators have the following limitations or
disadvantages:
They may not inhibit hydrate formation during startup. It may be
necessary to inhibit hydrate formation by injecting either methanol
or glycol until the gas flow and temperature stabilize.
Generally, an outside vendor must change the pressure drop on
the regulator.
When well output falls below normal production levels,
processors must remove and replace downhole regulators with another
hydrate inhibition method.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 15
When work is performed inside a wellbore, the well may be
permanently damaged.
Indirect Heaters
The advantages of using indirect heaters to inhibit the
formation of hydrates include the following:
Minimal maintenance or attention required
Very low chemical requirements
The disadvantages of using indirect heaters to inhibit hydrates
include the following:
Difficulty of supplying clean and reliable fuel to remote
locations
Large operating (fuel) costs if cheap fuel is not available
Potentially large capital costs
Significant plot space required
Special safety equipment needed because of fire hazard
Comparison of Temperature Control Methods
Figure 3 compares the use of downhole regulators and wellhead
heaters to inhibit hydrate formation. The high capital costs of
heaters generally limit their use to large hydrate inhibition
installations. Downhole regulators work best in large reservoirs
with high gas pressures that are not expected to decline
rapidly.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 16
DESIGN FACTORSDOWNHOLE
REGULATORS WELLHEAD HEATERS
Investment Very low Very high
Fuel None Very high
Operating Maintenance Low LowChemicals None Very low
Plot Area None Very high
Hazards High High
Downtime Low Low
Source: Dehydration and Hydrate Inhibition. Exxon Production
Research Company, Production
Operations Division. July 1986. With permission from Exxon
Production Research Company.
FIGURE 3: COMPARISON OF TEMPERATURE CONTROL METHODS
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 17
CALCULATING METHANOL INJECTION RATE REQUIRED TO INHIBIT HYDRATE
FORMATION IN A NATURAL GAS STREAM
Chemical Injection
Currently, methanol (MeOH) and monoethylene glycol (MEG) are the
two chemicals most commonly injected into gas streams to inhibit
hydrate formation. Consider the use of chemical injection to
inhibit hydrate formation for the following:
Gas pipelines in which hydrates form at localized points
Gas streams operating a few degrees above their hydrate
formation temperature
Gas-gathering systems in pressure-declining fields
Situations where hydrate problems are of short duration
Hydrate inhibitors act similarly to antifreeze. Adding a known
quantity of an inhibitor to a known quantity of pure liquid reduces
the hydrate-formation temperature by a calculable amount.
Equation for Calculating Required Depressions of
Hydrate-Formation Temperatures
Hydrate inhibitors act similarly to antifreeze. Adding a known
quantity of an inhibitor to a known quantity of pure liquid reduces
the hydrate-formation temperature by a calculable amount. Equation
1 calculates the required depression of hydrate-formation
temperatures as follows:
T = TH - Tminimum + S (Eqn. 1)
where:
T = Depression of hydrate-formation temperature, F
TH = Hydrate-formation temperature of gas stream, F
Tminimum = Minimum temperature of system, F
S = Safety factor to account for uncertainty in TH, F
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 18
Hammerschmidt Equation
The flow rate of the chemical inhibitor required to depress the
hydrate-formation temperature of a gas stream can be calculated by
hand or with computer programs. Computer programs (PRO/II and
HYSIM) use thermodynamic equations (Eqn. 2) that describe the
freezing point depression of an ideal solution.
T =
RT02
Hf In 1+
ninhibitornsolvent
(Eqn. 2)
where:
T = Depression of hydrate-formation temperature, F
R = Gas constant
T0 = Normal freezing point (absolute temperature scale)
Hf = Enthalpy of fusion per mole of solvent
ninhibitor = Moles of solute (inhibitor)
nsolvent = Moles of solvent
The simplification of Eqn. 2 for hand calculations results in
the Hammerschmidt equation (Eqn. 3). Theoretically, this equation
applies only to typical natural gases with solute concentrations
less than 0.20 mole fraction. In practice, however, the
Hammerschmidt equation has been successfully used for glycol
systems with inhibitor concentrations up to 0.40 mole fraction (70
wt % MEG) and with temperatures as low as -40F to -50F. The
Hammerschmidt equation is as follows:
T =
KHwI100M -MwI (Eqn. 3)
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 19
Equation 4 is the Hammerschmidt equation (Eqn. 3) solved for the
weight percent of inhibitor.
wI =
(T)(M)
KH + (T)(M) (100)
(Eqn. 4)
where:
w I = Weight percent of the chemical inhibitor in the
solution
T = Depression of hydrate-formation temperature, F
M = Molecular weight of the chemical inhibitor (methanol or
glycol)
KH = 2,335 for methanol and 4,000 for glycol
Methanol
Methanol works well as a hydrate inhibitor because of the
following reasons:
It can attack or dissolve hydrates already formed.
It does not react chemically with any natural gas
constituents.
It is not corrosive.
It is reasonable in cost.
It is soluble in water at all concentrations.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 20
Methanol significantly depresses hydrate-formation temperatures.
Figure 4 shows the effect of methanol on the hydrate-formation
temperature of propane.
Source: Katz, Donald L. and Robert L. Lee; Natural Gas
Engineering: Production and Storage. McGraw-Hill. 1990. With
permission from the Gas Processors Suppliers Association.
FIGURE 4: EFFECT OF METHANOL ON HYDRATE FORMATION IN PROPANE
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 21
Methanol Applications
Because methanols material cost is so low and its vapor losses
so high, methanol is often not recovered. Not requiring a recovery
system significantly reduces capital costs. Therefore, methanol
injection is generally economical for temporary installations,
situations with low gas volumes, or situations with mild,
infrequent, or seasonal hydrate problems.
For instance, the Uthmaniyah Gas Plant uses methanol injection
in case its solid desiccant dehydration system fails. Because of
its high volatility, methanol is also injected to inhibit hydrate
formation in pipelines.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 22
Methanol Injection System
Figure 5 shows a simplified schematic of a typical methanol
injection system. This system inhibits hydrate formation at a choke
or pressure-reducing valve. A gas-driven pump injects the methanol
into the gas stream upstream of the choke or pressure-reducing
valve. The temperature controller measures the temperature in the
gas stream and adjusts the power-gas control valve. The power-gas
control valve controls the flow of power gas, which controls the
methanol injection rate.
Source: Dehydration and Hydrate Inhibition. Exxon Production
Research Company, Production Operations Division. July 1986. With
permission from Exxon Production Research Company.
FIGURE 5: METHANOL INJECTION SYSTEM
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 23
Figure 6 shows the cycle of a typical methanol injection and
recovery system for a cryogenic application. The free-water
knockout first removes free water and other entrained liquids. Then
the system injects methanol into a gas-gas exchanger before the gas
stream enters a chiller. The methanol-hydrocarbon separator removes
the methanol from the gas stream. The water wash tower washes the
methanol from liquid hydrocarbons collected in the flash drum and
the methanol-hydrocarbon separator.
The reduction of the amount of free water in a gas stream before
the gas stream reaches the chemical injection point considerably
reduces the amount of chemical inhibitor required. A free-water
knockout installed at a wellhead removes free water, and thereby
reduces the amount of inhibitor needed.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 24
Methanol-hydrocarbon separator
Feed gas
Gas-gas exchanger
Chiller
Flash drum
Methanol injection pump Methanol
storage
Methanol still
Water wash tower Propane
product from depropanizer
Free- water knockout
Spray Nozzle
Dissolved gas
Vent gas
Reflux pump
Water surge drum
Excess water
HC gas
To fractionation
Washed propane
Source: Nielsen, R. B. and R. W. Bucklin. "Use of Methanol for
Hydrate Control in Expander Plants." Fluor Engineers and
Constructors, Inc. Presented at 1981 Gas Conditioning Conference.
With permission from Fluor engineers and Constructors, Inc.
FIGURE 6: METHANOL INJECTION AND RECOVERY SYSTEM
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 25
For instance, the saturated water content of gas at reservoir
conditions of 2,500 psia and 200F is 315 lb H2O/MMSCF. The
saturated water content of this same gas at wellhead conditions of
2,000 psia and 120F is 65 lb H2O/MMSCF. Therefore, the gas at
wellhead conditions contains 250 lb H2O/MMSCF of free water. If
this extra free water is not removed, extra chemical inhibitors
have to be used. However, the use of extra chemical inhibitors
increases the cost of the operation.
Method of Injecting Methanol - The injection of methanol
considerably upstream of a hydrate-forming location allows the
methanol to distribute and vaporize completely. Because of
methanols high volatility, nozzle placement and design are not as
critical as they are for glycol injection. Methanol injection
nozzles should be located as follows:
Upstream of front-end exchangers
At the inlets of turboexpanders
At any refrigerated condensers in downstream fractionation
To prevent the water-methanol solution from freezing in
turboexpander outlets operating below -102F, methanol injection
control must be very accurate.
Hammerschmidt Equation Modified for High Concentrations of
Methanol
The modified Hammerschmidt equation (Eqn. 5) accurately
calculates hydrate-formation temperature depressions for inhibitor
concentrations higher than 0.20 mole fraction and for methanol
injection systems that are operating with temperatures as low as
-160F.
T = -
RT02
Hf ln xwater
(Eqn. 5)
where:
T = Depression of hydrate-formation temperature, F
R = Gas constant
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 26
T0 = Normal freezing point (absolute temperature scale)
Hf = Enthalpy of fusion per mole of solvent
xwater = Mole fraction of water in the aqueous-methanol
solution
The substitution of methanol-specific values results in the
following:
T = -129.6 In 1- xMeOH( ) (Eqn. 6) where:
xMeOH = Mole fraction of MeOH in the aqueous-methanol
solution
Figure 37 (in Work Aid 1B) tabulates hydrate-formation
temperature depressions (?T) calculated by using the modified
Hammerschmidt equation (Eqn. 6).
Methanol depresses hydrate-formation temperatures a maximum of
234F at a concentration of 90 wt % or 0.835 mole fraction. At
concentrations higher than 90 wt %, methanol forms a solid at low
temperatures. Generally, methanol is not used at concentrations
above 30 wt %. However, applications that require maximum
depression of hydrate-formation temperatures, such as in a
turboexpander plant, generally use methanol concentrations of 90 wt
%.
Determining Methanol Injection Rates (General Applications)
This module covers two methods for calculating methanol
injection rates. The first method (general applications) does not
use high methanol concentrations (above 30 wt %) or compensate for
methanol solubility in hydrocarbon liquids. The second method
(cryogenic applications) considers both high methanol
concentrations and the solubility of methanol in hydrocarbon
liquids. It is covered in a later section.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 27
To determine methanol injection rates, the following conditions
need to be accounted for:
The amount of free water condensed from the natural gas after
chilling or expanding
The concentration of methanol required to depress the
hydrate-formation temperature
The flow rate of the gas stream
The solubility of methanol in the hydrocarbon vapor
Calculating Water Content of Gas Stream (W)
To determine the water content of the gas stream, use the
following methods, which were covered in ChE 206.01:
Gravity graphic
HYSIM
K-value
SimSci
To calculate the amount of water condensed out of the gas
stream, you need to determine the saturation temperature of the gas
stream. Although the condensation of hydrocarbons can be
significant in some cases, the methods used in this module to
calculate the amount of water condensed do not account for them.
The effect of hydrocarbon condensation can be accounted for by
developing overall mass balances and by applying the principles of
this module.
Determining Hydrate-Formation Temperature (TH)
For general applications, you can use the gravity graphic method
to determine hydrate-formation temperature. For cryogenic
applications (such as in a turboexpander plant), you should use a
more sophisticated method, preferably a computer program (such as
PRO/II or HYSIM).
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 28
Calculating Methanol Concentration Required to Depress
Hydrate-Formation Temperature
For methanol concentrations up to 30 wt %, use the Hammerschmidt
equation (Eqn. 3). Figure 32 (in Work Aid 1A) plots experimental
data that correspond to the Hammerschmidt equation.
Safety Margin (S) - For general applications that use methanol
concentrations below 30 wt %, a safety margin of 5F to 10F must be
applied to compensate for uncertainties in the Hammerschmidt
equation and in operating conditions. Because the Hammerschmidt
equation is conservative, 5F is generally sufficient.
Calculating Methanol Injection Rates (q MeOH)
The total methanol injection rate is calculated in two steps.
First, calculate the methanol injection rate required to achieve
the concentration of methanol in the aqueous solution which
inhibits hydrate formation (q MeOHaq). Then calculate the methanol
injection rate required to compensate for methanol vapor losses (q
MeOHvapor). The sum of the two injection rates is the total
methanol injection rate required to inhibit hydrate formation. The
equations developed in Work Aid 1 for the calculation of methanol
injection rates assume that pure methanol is injected. Calculating
Vapor Losses - Calculating the methanol injection rate to
compensate for vapor losses requires determining the methanol
vapor-to-liquid composition ratio. Figure 32 (in Work Aid 1A) plots
vapor-to-liquid composition ratios at various temperatures and
pressures. The following sample problem demonstrates how to
calculate a methanol injection rate by using Work Aid 1A. The nine
steps of this sample problem parallel the numbered steps of the
procedure summarized in Figure 30 and Figure 31 in Work Aid 1A.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 29
Sample Problem: Calculating Methanol Injection Rates (General
Applications) Calculate the methanol injection rate required to
inhibit the formation of hydrates in a saturated gas stream being
cooled in a chiller. Refer to Work Aid 1A.
Given: Gas specific gravity = 0.67 Inlet temperature=70F Chiller
temperature = 40F Operating pressure = 700 psia
Solution:
1. The gas stream is saturated at the inlet temperature,
70F.
2. The method covered in ChE 206.01 to determine the water
content of the gas at 70F and 40F is used to calculate that the
amount of free water condensed out of the gas stream in the chiller
is 12 lb H2O/MMSCF.
Winlet = 23 lb H2O/MMSCF (at 70F and 700 psia) Wchiller = 11 lb
H2O/MMSCF (at 40F and 700 psia) W = Winlet - Wchiller (Eqn. 7) = 23
lb H2O/MMSCF - 11 lb H2O/MMSCF = 12 lb H2O/MMSCF
3. The gravity graphic method covered in ChE 206.01 is used to
determine the hydrate-formation temperature of the gas stream is
58F.
4. The hydrate-formation temperature of the gas stream must be
depressed by 23F.
?T = TH - Tminimum + S (Eqn. 1) = 58F - 40F + 5F = 23F
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 30
5. A T of 23F and the Hammerschmidt equation (Eqn. 4) are used
to determine the gas stream requires a 24 wt % concentration of
methanol in the aqueous solution (w I).
w I =
(T)(M)
KH + (T)(M) (100)
(Eqn. 4)
=
23F( ) 32.0 lbmole
2,335 + 23F( ) 32.0 lbmole
100( )
= 24 wt % MeOH
6. The injection rate required to compensate for methanol vapor
losses is 28.1 lb MeOH/MMSCF.
By refering to Figure 33, the vapor-to-liquid composition ratio
is determined to be 1.17 lb MeOH/MMSCF/wt % MeOH at 40F and 700
psia.
q MeOHvapor = (vapor-to-liquid composition ratio)(w MeOH) (Eqn.
9)
q MeOHvapor =
1.17 lb MeOHMMSCF
wt % MeOH 24 wt % MeOH
= 28.1 lb MeOH/MMSCF
7. The methanol injection rate required to obtain 24 wt % MeOH
in the aqueous solution (q MeOHaq) is 3.8 lb/MMSCF.
q MeOHaq =
W( ) wMeOH( )w water (Eqn. 10)
=
12 lb H2O/MMSCF 24 wt % MeOH76 wt % H2O
= 3.8 lb MeOH/MMSCF
8. The total methanol injection rate (qMeOH) required is 31.9 lb
MeOH/MMSCF.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 31
q MeOHtotal = q MeOHvapor + q MeOHaq (Eqn. 11) = 28.1 lb
MeOH/MMSCF + 3.8 lb MeOH/MMSCF = 31.9 lb MeOH/MMSCF
9. The density of methanol found in Figure 46 is used to convert
the total injection rate to gal MeOH/MMSCF as follows:
= 31.9 lb MeOH
MMSCF
gal MeOH6.55 lb MeOH
= 4.9
gal MeOHMMSCF
Answer: The methanol injection rate required for this system
is
4.9 gal MeOH/MMSCF.
Calculating Methanol Injection Rates (Cryogenic
Applications)
The calculation of methanol injection rates for cryogenic
applications follows the same general procedure just described for
general applications. Calculations for cryogenic applications
require the following:
A much larger safety factor (typically, at least 35F)
The calculation of an additional methanol injection rate to
compensate for methanol absorbed by a liquid hydrocarbon
component
Graphs with more complete data
More precise methods of predicting hydrate-formation
temperatures
The use of very high methanol concentrations (90 wt %)
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 32
Work Aid 1B groups the steps of this procedure into the
following sequential tasks:
1. Calculating the water content and hydrate-formation
temperature of the gas stream (Figure 34)
2. Calculating the required depression of the hydrate-formation
temperature, the safety margin, and determining the solubility of
methanol in hydrocarbons (Figure 35)
3. Calculating the methanol injection rate (Figure 36)
Determining Water Content
As in the method for general applications, the amount of water
that is condensed out of the gas stream when the gas stream is
cooled or expanded in the chiller, separator, or other piece of
equipment must be calculated. Again, the saturation temperature of
the gas stream needs to be determined. Because graphs plotting data
for cryogenic conditions are in different units of measurement, the
flow rate of water needs to be converted to lb H2O/hr.
Determining Hydrate-Formation Temperature
To calculate the hydrate-formation temperature (TH) for the gas
stream, a method more sophisticated than the gravity graphic
method, such as the K-value method, or a computer program, such as
PRO/II, must be used.
Calculating Required Depression of Hydrate-Formation
Temperature
For most situations, you should use a concentration of 90 wt %
methanol in the aqueous solution and calculate the depressed
hydrate-formation temperature. A methanol concentration of 90 wt %
depresses hydrate-formation temperatures by 234F. Figure 37
tabulates the results of the modified Hammerschmidt equation (Eqn.
6).
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 33
Safety Margin - To adjust the flow rate of the injected
inhibitor, a concentration of methanol lower than 90 wt % may need
to be used. However, a proper safety margin (generally 35F) should
be maintained. The safety margin is the difference between the
hydrate-formation temperature and the depressed hydrate-formation
temperature (THdepressed). Safety margins should also be calculated
for downstream equipment.
The performance of a mass balance around the chiller, separator,
or other piece of equipment helps clarify the calculations. Figure
7 shows a mass balance around a separator.
Source: Reproduced with permission from Hydrocarbon Processing,
April 1983.
FIGURE 7: MASS BALANCE AROUND SEPARATOR
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 34
Determining Solubility of Methanol in Hydrocarbons
Figures 38, 39, and 40 in Work Aid 1B plot the solubility of
methanol in hydrocarbon vapor (the vapor-to-liquid composition
ratio) for different temperature ranges. Figure 41 in Work Aid 1B
plots the solubility of methanol in hydrocarbon liquid.
Because the data extrapolated from plant data (dashed line) is
more conservative, you should (when possible) use it. Even though
this data is relatively conservative, you should still add a safety
margin of 20%.
In addition to these figures, computer programs such as PRO/II
and HYSIM also calculate methanol losses. Results generated by
computer programs, however, should be compared with results from
other sources.
Calculating Methanol Injection Rates
As in the general method, the total methanol injection rate is
the sum of partial injection rates required to do the
following:
Achieve the required concentration of methanol in the aqueous
solution
Compensate for methanol vapor losses
Compensate for methanol lost when it dissolves into the
hydrocarbon liquid component
Injection Rate to Account for Vapor Losses - Because of the
units of measurement used in Figures 38, 39, and 40, the
calculation of the injection rate to account for vapor losses
requires multiplication of the vapor-to-liquid composition ratio by
the flow rate of the hydrocarbon vapor, instead of the gas stream
feed rate. The conversion of the injection rate to lb MeOH/hr
requires the use of the conversion factor of 379.5 SCF/lb-mole.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 35
Injection Rate to Account for Solubility Hydrocarbon Liquid -
Because of the units of measurement used in Figure 41, the
calculation of the injection rate to account for solubility
hydrocarbon liquid requires multiplication of the solubility of
methanol by the flow rate of the hydrocarbon liquid and the
molecular weight of methanol (32 lb/mole).
The following sample problem demonstrates how to calculate a
methanol injection rate for a cryogenic application by using Work
Aid 1B. The fourteen steps of this sample problem parallel the
numbered steps of the procedure summarized in Figure 34, Figure 35,
and Figure 36 in Work Aid 1B.
Sample Problem: Calculating Methanol Injection Rates (Cryogenic
Applications) Referring to Work Aid 1B, calculate the methanol
injection rate required to inhibit hydrate formation in a
separator. Figure 8 shows the flow of the gas stream. A gas-gas
exchanger and a chiller cool the gas stream before it is
separated.
Given:
Source: Nielsen, R. B. and R. W. Bucklin. "Use of Methanol for
Hydrate Control in Expander Plants." Fluor Engineers and
Constructors, Inc. Presented at 1981 Gas Conditioning Conference.
With permission from Fluor Engineers and Constructors, Inc.
FIGURE 8: FLOW OF GAS STREAM IN METHANOL INJECTION SAMPLE
PROBLEM (CRYOGENIC)
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 36
Solution:
1. The water content of the inlet gas is given.
2. The methods described in the ChE 206.01 are used to determine
that the amount of free water condensed out of the gas stream (W)
is 2.24 lb H2O/MMSCF.
From ChE 206.01:
Woutlet = 0.012 lb H2O/MMSCF
W = Winlet - Woutlet (Eqn. 7) = 2.25 lb H2O/MMSCF - 0.012 lb
H2O/MMSCF = 2.24 lb H2O/MMSCF
3. The flow rate of the condensed water is 168 lb H2O/hr.
qwater = (W)(q gas stream)
1 day24 hr
(Eqn. 12)
=
2.24 lb H2OMMSCF
1,800 MMSCFday
1 day24 hr
= 168
lb H2Ohr
4. The methods from ChE 206.01 are used to determine that the
hydrate-formation temperature (TH) of the gas stream is 45F.
5. By using 90 wt % MeOH in the aqueous solution and referring
to Figure 37, the depressed hydrate-formation temperature is
determined to be -189F.
From Figure 38:
?T = 234F THdepressed = TH - ? T (Eqn. 13) = 45F - 234F =
-189F
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 37
6. A methanol concentration of 90 wt % provides a safety margin
of 89F.
S = Tminimum - (TH - T) (Eqn.14) = -100F - (45F - 234F) =
89F
7. By referring to Figure 39, and using the values for the
temperature (-100F) and the pressure (600 psia) in the separator,
the solubility of methanol in hydrocarbon vapor is determined to be
0.83 lb MeOH/MMSCF/mole fraction MeOH in the aqueous solution.
8. The plant data in Figure 41 is used to calculate the
solubility of methanol in hydrocarbon liquid at -100F. The addition
of a 20% safety margin results in the following:
From Figure 41: Solubility of MeOH in HCliquid= 0.2 mole
MeOH
100 mole HC liquid
Adding a 20% safety margin: = 0.24 mole MeOH
100 mole HC liquid
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 38
Figure 9 shows the mass balance around the separator.
Source: Reproduced with permission from Hydrocarbon Processing,
April 1983.
FIGURE 9: MASS BALANCE AROUND SEPARATOR IN METHANOL INJECTION
SAMPLE PROBLEM
(CRYOGENIC)
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 39
9. The methanol injection rate required to account for methanol
vapor losses (q MeOHvapor) is 45 lb MeOH/hr. From Figure 37, 90 wt
% methanol equals 0.835 mole fraction.
q MeOHvapor = (vapor-to-liquid composition ratio)(xMeOH)
(qHCvapor)
379. 5SCF
lb -mole106
(Eqn. 15)
q MeOHvapor =
0.83 lb MeOHMMSCF
mole fraction MeOH 0.835 mole fraction MeOH
173,000 mole HCvaporhr
379.5 SCF
lb-mole
106
=
45 lb MeOHhr
10. The methanol injection rate required to account for methanol
dissolved in hydrocarbon liquid is 1,940 lb MeOH/hr. From Figure
46, the molecular weight of methanol (MMeOH) is 32 lb/mole.
q MeOHliquid = Solub ility of MeOH in HCliquid( ) qHCliquid(
)MMeOH( )
(Eqn. 16)
=
0.24 mole MeOH100 mole HC liquid
25,200 mole HC liquid
hr 32 lb MeOH
mole MeOH = 1,940 lb MeOH/hr
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 40
11. The methanol injection rate required to obtain a
concentration of 90 wt % MeOH in the aqueous solution is 1,510 lb
MeOH/hr.
q MeOHaq =
w MeOHaq q waterw wateraq (Eqn. 17)
=
90 lb MeOH100 lb aqueous solution
168 lb H2O
hr
100 lb aqueous solution10 lb H2O
= 1,510 lb MeOH/hr
12. The total methanol injection rate required for this system
is 3,500 lb MeOH/hr.
q MeOHtotal = q MeOHvapor + q MeOHliquid+ q MeOHaq(Eqn. 18) = 45
lb MeOH/hr + 1,940 lb MeOH/hr + 1,510
lb MeOH/hr = 3,495 lb MeOH/hr 3,500 lb MeOH/hr
13. From Figure 42, the density of methanol at 100F is 6.47
lb/gal. The conversion of the units of the methanol injection rate
results in the following:
q MeOH = (q MeOHtotal)
1densityMeOH
1hr
60min
(Eqn. 19)
= 3,500lbMeOH
hr
gal MeOH6.47 lb MeOH
hr
60 min
= 9.0 gpm
Answer: The methanol injection rate required for this system is
9.0 gpm.
Source: Nielsen, R. B. and R. W. Bucklin. Use of Methanol for
Hydrate Control in Expander Plants. Fluor Engineers and
Constructors, Inc. Presented at 1981 Gas Conditioning Conference.
With permission from Fluor Engineers and Constructors, Inc.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 41
CALCULATING GLYCOL INJECTION RATE REQUIRED TO INHIBIT HYDRATE
FORMATION IN A NATURAL GAS STREAM
Like methanol, glycol inhibits hydrate formation when injected
into gas streams. Figure 10 compares the advantages and
disadvantages of glycol and methanol injection.
INHIBITOR ADVANTAGES DISADVANTAGES/ LIMITATIONS
Glycol Usually lower operating cost than methanol when both
systems recover injected chemical
Low vapor losses (low volatility)
High initial cost
Possibility of glycol contamination
Limited use (only noncryogenic applications)
Cannot dissolve hydrates already formed
Methanol Relatively low initial cost Simple system
Does not generally need to be recovered
Low viscosity
When injected, distributes well into gas streams
Can dissolve hydrates already formed
High operating cost
Generally, use glycol injection if methanol injection rate is
over 30 gph
Large vapor losses (high volatility)
FIGURE 10: COMPARISON OF CHEMICAL INJECTION INHIBITORS
Glycol does not evaporate as easily as methanol. In some
applications, glycol does not dissolve into liquid hydrocarbons as
easily as methanol. Glycol solubility in hydrocarbon liquid
increases with:
Glycol molecular weight
Temperature increase
Increase in glycol concentration in water-glycol mixture
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 42
Glycol solubility also depends on hydrocarbon type. Glycols are
more soluble in aromatics and naphthenes than in paraffin
hydrocarbons. Glycol solubility in hydrocarbons at 60F and for
50-70 wt % of glycol concentrations, range from 10 to 50 ppm for EG
and 20 to 100 ppm for DEG. These losses are ~0.3 to 3 gal glycol
per 1000 barrels of condensate. Recovering glycol, therefore, is
generally more economical than recovering methanol. Economical
recovery of glycol often lowers its operating cost below methanols
operating cost because recovery compensates for higher material
cost. As a general rule, if the calculated methanol injection rate
for a natural gas stream exceeds 30 gph, glycol injection should be
chosen.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 43
Glycol Concentration and Dilution
In addition to inhibiting hydrate formation, you also need to
choose glycol concentrations that do not freeze. Figure 11 shows
the freezing points of various aqueous glycol solutions.
KEY: MEG = Monoethylene glycol DEG = Diethylene glycol TEG =
Triethylene glycol TREG = Tetraethylene glycol (not generally used
for hydrate inhibition)
Source: Engineering Data Book, Vol. 2, 10th ed. GPSA, Tulsa.
1987. With permission from the Gas Processors Suppliers
Association.
FIGURE 11: FREEZING POINTS OF AQUEOUS GLYCOL SOLUTIONS
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 44
Note that solutions with glycol concentrations between about 60
wt % and 80 wt % do not freeze. Because of this, glycol solutions
are generally kept between these concentrations, even if lower
concentrations are required to depress the hydrate-formation
temperature.
When glycol injection is performed below 20F, the glycol
freezing point must be considered. Glycols crystallize, but do not
freeze solid, which inhibits flow and proper separation. For this
reason, it is common practice to keep glycol concentrations between
60-80 wt %.
If unknowns exist, the inhibitor should not be diluted over
5-10% by the pipeline stream being inhibited. For pipeline
protection above 20F, a greater dilution may be tolerated but
should not exceed ~20%. For spot injection, such as a heat
exchanger, where distribution is a problem, dilution may be limited
to 5%.
To avoid the formation of emulsions, the water content of the
injected inhibitor (lean glycol) solution should be greater than 20
wt %. Therefore, the injection rate of pure glycol required by the
system to inhibit hydrate formation is first calculated and then
the injection rate of the lean glycol solution is calculated.
To keep the concentration of the glycol between 60 wt % and 80
wt %, the extent to which the free water dilutes the injected
glycol must be determined. Figure 12 lists and summarizes dilution
restrictions.
SITUATION
ALLOWABLE OR RECOMMENDED DILUTION OF
GLYCOL
Unknowns about the systemexist Not over 5% to 10%
Spot injection (in a heatexchanger, for example)
If distribution of glycol is aproblem, limit to about 5%
Pipelines operating above 20F Up to about 20%
Source: Francis S. Manning and Richard E. Thompson's Oilfield
Processing of Petroleum, Volume One: Natural Gas. Copyright
PennWell Books, 1991.
FIGURE 12: ALLOWABLE GLYCOL DILUTIONS
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 45
Selecting Glycol Type The glycols normally used for hydrate
inhibition are the following:
MEG
DEG
TEG
Selection of the appropriate type of glycol depends on the
composition of the gas stream and on information provided by the
glycol vendor.
For instance, Dow Chemical recommends that its glycols be used
at concentrations of 70 wt % to 75 wt % to avoid freezing problems.
Dow Chemical also makes the recommendations for selecting glycols
listed in Figure 13.
SITUATION/CONDITION RECOMMENDATION
Natural gas transmission inwhich recovery is not important
Use MEG because it depresses hydrate-formation temperatures the
most.
Injected glycol contactshydrocarbon liquids
Use MEG because it has the lowestsolubility of the glycols in
high molecular-weight hydrocarbons.
Severe vapor losses Use DEG or TEG because both glycolshave
lower vapor pressures than the otherglycols.
Severe vapor losses andinjected glycol contactshydrocarbon
liquids
When both of these conditions are present,DEG may be the best
choice
Source: Dow Chemical reported by Exxon, p. 16.
FIGURE 13: DOW CHEMICAL GLYCOL RECOMMENDATIONS
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 46
Glycol Injection and Recovery System
To help you understand the method for calculating glycol
injection rates, this section briefly describes two glycol
injection and recovery systems. The two systems differ in the
method used to remove the glycol from the hydrocarbons. The first
system uses two separators: one separator removes glycol from
hydrocarbon gas and the other separator removes glycol from
hydrocarbon liquid. The second system uses a three-phase single
separator that combines these two steps. This system also includes
the control system for varying the glycol injection rate.
Glycol Injection and Recovery System Using Two Separators
Figure 14 shows a typical glycol injection and recovery system
that uses a low temperature separator and a glycol-oil separator.
In this system, glycol injection inhibits the formation of hydrates
while a heat exchanger and a choke cool the gas stream.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 47
Source: Francis S. Manning and Richard E. Thompson's Oilfield
Processing of Petroleum, Volume One: Natural Gas. Copyright
PennWell Books, 1991.
FIGURE 14: GLYCOL INJECTION AND RECOVERY SYSTEM
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 48
The glycol injection and recovery system shown in Figure 14 uses
the following:
A free-water knockout to remove free water from the gas
stream.
Glycol injection just before the heat exchanger and just before
the choke.
A low-temperature separator to remove gas from the gas,
glycol-water, and hydrocarbon mixture.
The separated cold, dry gas to pre-cool the gas stream in the
gas-gas heat exchanger.
A glycol-oil separator to remove rich glycol from the
hydrocarbon condensate.
The rich glycol to cool the regenerated glycol in the
glycol-glycol heat exchanger.
A glycol regenerator fired by fuel gas to regenerate the glycol
to the specified concentration for injection.
Glycol Injection and Recovery System Using a Three-Phase
Separator
Figure 15 shows a typical glycol injection and recovery system
that uses a three-phase separator. The power-gas-driven pump, the
temperature controller, and the injection point shown in Figure 15
are similar to the methanol injection system shown in Figure 5. A
gas-driven pump injects the glycol into the gas stream upstream
from the choke or pressure-reducing valve. The temperature
controller measures the temperature in the gas stream and adjusts
the power-gas control valve. The power-gas control valve controls
the flow of power gas, which controls the injection rate.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 49
Source: Dehydration and Hydrate Inhibition. Exxon Production
Research Company, Production Operations
Division. July 1986. With permission from Exxon Production
Research Company.
FIGURE 15: GLYCOL INJECTION AND RECOVERY SYSTEM
(THREE-PHASE)
The recovery side of the system shown in Figure 15 includes a
reboiler and a three-phase separator. The glycol injection and
recovery cycle is as follows:
The injection nozzle injects the lean glycol into the gas
stream.
The lean glycol absorbs the water and inhibits hydrate formation
in the choke or pressure-reducing valve.
The three-phase separator separates the water and rich glycol
from the hydrocarbon gas and liquid.
The separated components are piped to their respective
destinations.
The reboiler boils off excess water from the rich glycol, and
thereby prepares it to be injected again.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 50
Glycol Injection and Recovery System Components
Separators
The low-temperature separator shown in Figure 14 separates the
hydrocarbon gas from the hydrocarbon condensate-rich glycol
mixture. The glycol-oil separator in Figure 14 flashes the
remaining hydrocarbon condensate-rich glycol mixture to a low
pressure and then separates out the rich glycol. As shown in Figure
15, three-phase separators combine the functions of the
low-temperature separator and the glycol-oil separator by
separating the inhibited gas stream into cold gas, hydrocarbon
condensate, and rich glycol in one vessel.
Separating the rich glycol from the hydrocarbon liquid is more
difficult than separating hydrocarbon liquid from vapor. Performing
both separations in one vessel sacrifices some effectiveness and
efficiency. Generally, three-phase separators require longer
residence times (20 to 40 minutes) and suffer higher glycol
losses.
Reboiler
The temperature in the reboiler depends on the type and
concentration of the glycol used. Reboilers in hydrate inhibition
systems do not regenerate glycols to the same high levels of purity
used in dehydration systems.
Figure 16 plots boiling temperatures of MEG. For example, Figure
16 shows that the temperature of the reboiler should be set at
about 250F to achieve a lean MEG concentration of 75 wt % at 1 atm
(absolute). It is important not to exceed the boiling point of pure
glycol because doing so causes thermal degradation.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 51
KEY: B = Boiling curve C = Condensing curve
Source: Dehydration and Hydrate Inhibition. Exxon Production
Research Company, Production Operations Division. July 1986. With
permission from Exxon Production Research Company.
FIGURE 16: BOILING POINT OF MEG
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 52
Inhibitor Pump
A drum on top of a typical power-gas-driven pump contains the
inhibitor: methanol or glycol. The drum connects directly to the
pump (generally, a positive displacement pump). Methods for
monitoring the inhibitor injection rate include inserting a
calibrated dipstick through the top of the drum or pumping the
inhibitor into a measured vessel. Drums are replaced when
empty.
Glycol Losses
Glycol injection systems that involve both hydrocarbon liquids
and gases generally lose glycol to the following:
Solubility (normally about 0.3 to 3 gallons of glycol per 1000
barrels of hydrocarbon liquid produced)
Leakage
Carryover with hydrocarbon liquid and in the reboiler
Vaporization in the reboiler and during injection
Nozzle Selection and Placement
Nozzle selection and placement indirectly affect glycol
injection calculations. Although calculated to inhibit hydrate
formation, injection rates may need to be adjusted to maintain a
flow rate or pressure recommended for a particular nozzle design or
placement.
Because of glycols low vapor pressure, nozzle design is more
critical for glycol than it is for methanol. To mix adequately with
the natural gas, glycol requires a fine, well-distributed mist.
Also, to inhibit hydrates fully, the nozzle must be placed to
ensure full coverage. Installing backup nozzles in parallel with
the primary nozzle allows nozzle removal, replacement, or
inspection without interrupting inhibitor service.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 53
Nozzle Selection - Nozzle design is especially important in the
design of glycol injection systems for cold separation facilities.
The criteria for selecting a nozzle include the following:
Capacity
Spray angle
Sufficient pressure drop between the nozzle and the gas stream
over the expected range of operating conditions
Normally, a pressure differential of 100 psi to 150 psi
sufficiently atomizes glycol. Also, gas stream velocities above 12
ft/s help ensure atomization. Nozzle Placement - Normally, nozzles
are located just upstream of the heat exchanger or chiller where
hydrates form. The spray from a properly located nozzle covers the
entire tube sheet of a heat exchanger. Inadequate atomization
causes the formation of glycol droplets that settle and flood the
bottom of the heat exchanger. As a result, the glycol inhibits
hydrate formation in the bottom, but not the top, of the heat
exchanger. Flooding of the bottom of the heat exchanger also
significantly decreases its effectiveness. Figure 17 shows injected
glycol fully covering the tube sheet of a heat exchanger.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 54
Source: Rosen, Ward; Manual P-8: Hydrate Inhibition, 2nd ed.
Petroleum Learning Programs, Ltd. Houston. 1991. With permission of
Petroleum Learning Programs, Ltd.
FIGURE 17: GLYCOL SPRAYED ONTO THE TUBE SHEET OF A HEAT
EXCHANGER
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 55
Inadequate coverage can leave some tubes with a concentration of
glycol that is too low, which will result in the formation of
hydrates. As shown in Figure 18, hydrates plug the tubes, and
thereby increase the differential pressure across the heat
exchanger.
Source: Rosen, Ward; Manual P-8: Hydrate Inhibition, 2nd ed.
Petroleum Learning Programs, Ltd. Houston. 1991. With permission of
Petroleum Learning Programs, Ltd.
FIGURE 18: INCREASE IN PRESSURE DROP BECAUSE OF HYDRATE
FORMATION
Figure 19 shows three nozzle placements. Locating the nozzle too
close to the tube sheet reduces coverage. Locating the nozzle too
far from the tube sheet produces too wide a spray, which provides
too little glycol to the tube sheet.
Spray pattern with Spray pattern with Spray pattern with proper
nozzle nozzle too close nozzle too far location to tube sheet from
tube sheet
Source: Rosen, Ward; Manual P-8: Hydrate Inhibition, 2nd ed.
Petroleum Learning Programs, Ltd. Houston.
1991. With permission of Petroleum Learning Programs, Ltd.
FIGURE 19: NOZZLE PLACED AT THREE LOCATIONS: ONE FLOW RATE
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 56
Figure 20 shows one nozzle location but three flow rates. Too
low a nozzle flow rate produces the same result as a nozzle located
too close to the tube sheet. Too high a nozzle flow rate produces
the same result as a nozzle located too far from the tube
sheet.
Glycol Glycol Glycol Spray pattern at Spray pattern at Spray
pattern at proper glycol high glycol low glycol flow rate flow rate
flow rate Source: Rosen, Ward; Manual P-8: Hydrate Inhibition, 2nd
ed. Petroleum Learning Programs, Ltd. Houston.
1991. With permission of Petroleum Learning Programs, Ltd.
FIGURE 20: NOZZLE PLACED AT ONE LOCATION: THREE FLOW RATES
Calculating Glycol Injection Rates Calculating glycol injection
rates is similar to calculating methanol injection rates, but it is
more critical to maintain the glycol solution between 60 wt % and
80 wt %. Also, glycol vapor losses are insignificant: therefore,
you do not need to account for them.
The method used to calculate methanol injection rates can be
used for glycol. However, because dilution is much more critical
for glycol, the method must be altered to account for glycol
dilution restrictions.
If you account for vapor and solubility losses, you can also use
this method for calculating methanol injection rates. With
methanol, however, the methanol concentration required to inhibit
hydrates is generally the minimum concentration allowed.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 57
The following sections briefly describe the method for
calculating glycol injection rates and how it differs from the
method for calculating methanol injection rates.
Water Content, Hydrate-Formation Temperature, and Safety
Margin
As in the methanol calculations, the saturation temperature of
the gas stream needs to be determined. Whether the saturation
temperature of the gas stream is equal to or greater than the
temperature of the gas stream needs to be determined.
For most applications, the gravity graphic method is sufficient.
However, computer programs are best for design and critical
applications.
Equation 1 in Work Aid 1 uses a 5F safety margin (S) because it
is usually adequate to calculate the required depression of the
hydrate-formation temperature.
Concentration of Glycol
As with methanol, the Hammerschmidt equation (Eqn. 4) is used to
calculate the minimum glycol concentration that depresses the
hydrate-formation temperature of the gas stream.
wI =
(T) (M)
KH + (T) (M) (100)
(Eqn. 4)
where: w I = Weight percent of the chemical inhibitor
T = Depression of hydrate-formation temperature, F
M = Molecular weight of the chemical inhibitor (methanol or
glycol)
KH = 2,335 for methanol and 4,000 for glycol
Figure 50 in Work Aid 2 plots the results of the Hammerschmidt
equation solved for weight percent (Eqn. 4). These graphs greatly
simplify the calculation of inhibitor injection rates.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 58
Effects of Dilution Restrictions on Calculating Glycol
Concentrations
Lean Glycol Solution - Because of glycols dilution restrictions,
you need to determine the concentration of lean glycol (w lean).
Vendor specifications and/or reboiler temperatures usually dictate
the concentration of lean glycol (usually less than 80 wt %
glycol). Because pure glycol is not generally used, glycol
injection rates need to be increased to account for dilution. Rich
Glycol Solution - Because dilution restrictions also apply to the
glycol concentration required to depress the hydrate-formation
temperature (w rich), the glycol concentration calculated by the
Hammerschmidt equation needs to be compared to the vendor dilution
recommendations. If the glycol concentration required to depress
the hydrate-formation temperature is lower than the minimum glycol
concentration recommended by the vendor (usually greater than 60 wt
% glycol), the glycol concentration recommended by the vendor
should generally be used.
Dilution of Rich Glycol Solution - In addition to the
restrictions on the concentrations of the lean and rich glycol
solutions, the dilution of the lean glycol may need to be limited.
The concentration of the rich glycol solution should be calculated
by subtracting the allowed amount of dilution recommended in Figure
12 or recommended by a vendor from the concentration of the lean
glycol.
Equation for Calculating Inhibitor Injection Rate - Once the
concentrations of the lean and rich glycol solutions have been
determined, an inhibitor injection rate that maintains both
concentrations should be calculated. Equation 22 calculates
inhibitor injection rates.
q injection =
W 1
100wrich
-100
w lean
qgas stream
(Eqn. 22)
where: q injection = Inhibitor injection rate
W = Water condensed from gas stream
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 59
w rich = Weight percent of glycol in the rich glycol
w lean = Weight percent of glycol in lean glycol
q gas stream = Flow rate of gas stream The following sample
problem demonstrates how to calculate glycol injection rates by
using Work Aid 2. The eleven steps of this sample problem parallel
the numbered steps of the procedure summarized in Figure 44 and
Figure 45 in Work Aid 2.
Sample Problem: Calculating Glycol Injection Rates Referring to
Work Aid 2, calculate the glycol (MEG) injection rate required to
inhibit hydrates in the following gas stream cooled in a buried
pipeline.
Given:
Operating pressure = 900 psia Minimum operating temperature =
45F Saturation temperature of gas stream = 90F Gas stream flow rate
= 10 MMSCFD Specific gravity = 0.7
Solution:
1. The water content at the saturation temperature is
substracted from the water content at the operating temperature
which results in a free water (q water) flow rate of 38.4 lb
H2O/MMSCF.
From ChE 206.01: WTsaturation = 48 lb H2O/MMSCF WTminimum = 9.6
lb H2O/MMSCF
W = WTsaturation - WTminimum (Eqn. 8) = 48 lb H2O/MMSCF - 9.6 lb
H2O/MMSCF = 38.4 lb H2O/MMSCF
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 60
2. The water content is multiplied by the gas stream flow rate,
which results in the following:
q water = W (q gas stream) (Eqn. 20)
= 38.4
lb H2OMMSCF
10 MMSCFday
= 384
lb H2Oday
3. By the gravity graphic method (covered in ChE 206.01), the
hydrate-formation temperature is 64F.
4. The minimum operating temperature is subtracted from the
hydrate-formation temperature, and a safety factor is added, which
results in the required depression of the hydrate-formation
temperature of 24F.
T = TH - Tminimum + S (Eqn. 1) = 64F - 45F + 5F = 24F
5. The Hammerschmidt equation solved for the weight percent of
inhibitor (Eqn. 4) is used to determine that the system requires a
27 wt % concentration of glycol.
w I =
(T)(M)
KH + (T)(M) (100)
(Eqn. 4)
=
(24)(62.10)(4,000) + (24)(62.10)
(100)
= 27 wt % MEG
6. Let us suppose that the vendor recommends a lean glycol
concentration of 75 wt % MEG.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 61
7. If there is an allowable dilution of 10%, the concentration
of the rich glycol is 65 wt % MEG.
w rich = w lean - (allowable dilution) (Eqn. 21) = 75 wt % MEG -
10% = 65 wt % MEG
8. The rich glycol solution calculated in Step 7 is used because
it satisfies both hydrate inhibition and dilution restriction
conditions.
9. From Figure 48, 65 wt % MEG and 75 wt % MEG do not
freeze.
10. Equation 22 is used to determine that the system requires
1,870 lb pure MEG/day.
q injection =
W 1
100wrich
-100
w lean
qgas stream
(Eqn. 22)
=
38.4 lb H2O
MMSCF 1
100 lb solution65 lb MEG
- 100 lb solution75 lb MEG
10 MMSCFday
= 1,870 lb MEG
day
11. The value calculated in Step 9 and the density of MEG (from
Figure 49 assuming an injector solution temperature of 90F) are
used to determine that the system requires a lean glycol injection
rate of 276 gpd.
q injection = 1870lb MEG
dayx
100lb leanglycol solution75lb MEG
xgalleanMEG
9.07 lbleanMEG
= 275galleanMEG solution
day
Answer:
This system requires a minimum injection rate of 276 gallons of
75 wt % MEG (at 90F) per day.
-
Engineering Encyclopedia Dehydration and Hydrate Inhibition
Hydrate Inhibition Methods
Saudi Aramco DeskTop Standards 62
Calculating Glycol Injection Rates: Graphical Method
You can also use graphs to calculate glycol injection rates.
When available, graphs