hydrate inhibition methods

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



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



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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 (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



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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 (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



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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



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



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



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.




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.




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




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.




FIGURE 1: TYPICAL INDIRECT HEATER

Wellhead heaters - Figure 2 shows a schematic of a typical wellhead heater.

FIGURE 2: TYPICAL WELLHEAD HEATER INSTALLATION




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.




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.




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.




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




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




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:


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)




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


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.




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




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.




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




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.




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




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:


R = Gas constant




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.




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).




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.




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




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.




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 %)




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).




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




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.




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)




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




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




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)




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




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.




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




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.




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




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




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




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.




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




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.




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.




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.




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




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.




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.




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




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




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.




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


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.




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




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




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.




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.




Calculating Glycol Injection Rates: Graphical Method

You can also use graphs to calculate glycol injection rates. When available, graphs

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