Offshore Hydrate Engineering Handbook

a manuscript funded by

ARC0 Exploration and Production Technology, Co.

E. Dendy Sloan, Jr. Center for Hydrate Research Colorado School of Mines Golden, Colorado 80401

assisted in production by M.B. Seefeldt

January 1, 1998

Table of Contents

Topic

Table of Contents .._..................................... ..ii

Disclaimer and Acknowledgements. ....................................................................... .v

Introduction .......................................................................................................... 1

I. Safety First: A Gallon of Prevention is Worth a Mile of Cure.. _. .._......_.._......... 1

II. Prevention by Design: How to Ensure Hydrates Wont Fog ............................... 5

A. Where Do Hydrates Form in Offshore Systems?. .................................... .6

B. A One Minute Estimate of Hydrate Formation (Accurate to *SO%). ....... .l 1

C. A Ten Minute Estimate ofFormation/Inhibition (Accurate to &25%).......12 1. Hydrate Formation Conditions by the Gas Gravity Method.. ........ 13

2. Estimating the Hydrate Inhibitor in the Free Water Phase ............ .14 3. Amount of Inhibitor Injected Into Pipeline .................................. 16

a. Amount of Water Phase.. ............................................... 16 b. Amount of Inhibitor Lost to the Gas Phase ..................... .17 c. Amount of Inhibitor Lost to the Liquid Phase ................. .17

4. Example Calculation of Amount Methanol Injection .................... .17 5. Computer Program for Second Approximation ........................... .20

D. Most Accurate Calculation of Hydrate Formation/Inhibition. ................. .23 1. Hydrate Formation and Inhibitor Amounts in Water Phase ............ 23 2. Conversion ofMeOH to MEG Concentration in Water Phase........2 5 3. Solubility of MeOH and MEG in the Gas .................................... .25 4. Solubility of MeOH and MEG in the Condensate ......................... .26 5. Best Calculation Technique for MeOH or MEG Injection ............ .26

E. Case Study: Prevention of Hydrates in Dog Lake Field Pipeline ............. .30

F. Hydrate Limits to Expansion through Valves or Restrictions ................... . 1 1. Rapid Calculation of Hydrate-Free Expansion Limits. .................. .33 2. More Accurate Calculation of Hydrate-Free Gas Expansion..........3 4 3. Methods to Prevent Hydrate Formation on Expansion ................ ..3 6

ii

G. Hydrate Control Through Chemical Inhibition and Heat Management .... ..4 1 1. Inhibition with Methanol or Mono-ethylene Glycol.. ................... .42

a. Methanol ...................................................................... .42 b. Monoethylene Glycol.. .................................................. .44 c. Comparison of Methanol and Glycol Injection ................. .45

2. Kinetic Control by Anti-Agglomerants and Kinetic Inhibitors ....... .45 a. Anti-Agglomerants.. ..................................................... ..4 6 b. Kinetic Inhibition ........................................................... .47

3. Guidelines for Use of Chemical Inhibitors.. ................................ ..5 0 4. Heat Management.. ................................................................... .53

a Insulation Methods.. ...................................................... ..5 4 b Pipeline Heating Methods.. ............................................ ..5 5

H. Design Guidelines for Offshore Hydrate Prevention ............................... .55

III. Hydrate Plug Remediation.. ........................................................................... ..5 8

A. How Do Hydrate Blockages Occur?. ................................................... ..5 9 1. Concept of Hydrate Particle and Blockage Formation ................. .59 2. Process Points of Hydrate Blockage.. ...................................... ..6 1

B. Techniques to Detect Hydrates.. ........................................................... .62 1. Early Warning Signs for Hydrates ............................................. .63

a. Early Warnings in Subsea Pipelines.. ............................... ..6 3 b. Early Warnings Topside on Platforms .............................. .66

2. Detection of Hydrates Blockage Locations.. .............................. ..6 7 a. Inhibitors or Mechanical/Optical Devices. ......................... .68 b. Pressure Location Techniques ......................................... .69 c Measuring Internal Pressure through External Sensors ....... .72 d. Recommended Procedure to Locate a Hydrate Plug .......... .73

C. Techniques to Remove a Hydrate Blockage.. ........................................ ..7 4 1. Depressurization of Hydrate Plugs.. .......................................... ..7 4

a. Conceptual Picture of Hydrate Depressurization ............... .75 b. Hydrate Depressurization from Both Sides of Plug ............ .77 c. Depressurization of Plugs with Significant Liquid Heads.....8 3 d. Depressurizing One Side of Plug(s) ................................. .85

2. Chemical Methods of Plug Removal. ......................................... ..8 8 3. Thermal Methods of Plug Removal.. ........................................ ..8 9 4. Mechanical Methods of Plug Removal.. ..................................... ..9 0

D. Avoiding Hydrates on Flowline Shut-in or Start-up ............................... .91

E. Recommendations and Future Development Areas ................................. .93 1. Recommendation Summary for Hydrate Remediation .................. .93 2. Recommendations for Future Work.. .......................................... .94

IV. Economics .................................................................................................. ..9 5

A, The Economics of Hydrate Safety.. ...................................................... ..9 5 B. The Economics of Hydrate Prevention.. ................................................ .95

1. Chemical Injection Economics.. ................................................. .95 a. Economics of Methanol and Mono-ethylene Glycol... ........ .96 b. Economics of New Types of Inhibitors.. ............................ 98

2. Heat Management Economics.. ................................................. 100 a. Economics of Insulation.. ............................................... 100

C. The Economics of Hydrate Remediation .............................................. ,101

Appendix A. Gas Hydrate Structures, Properties, and How They Form.. ............... .I03 1. Hydrate Crystal Structures.. ................................................................ 103 2. Properties Derive from Crystal Structures.. ......................................... ,104

a. Mechanical Properties of Hydrates ............................................ ,104 b. Guest: Cavity Size Ratio: a Basis for Property Understanding ...... 105 c. Phase Equilibrium Properties.. .................................................. ,106 d. Heat of Dissociation ................................................................ ,107

3. Formation Kinetics Relate to Hydrate Crystal Structures ...................... ,107 a. Conceptual Picture of Hydrate Growth. .................................... .I07

Appendix B. Users Guide for HYDOFF and XPAND Programs.. ........................ ,109 B.l.HYDOFF.. .................................................................................... .I09 B.2. XFAND.. ...................................................................................... ,123

Appendix C. Additional Case Studies of Hydrate Blockage and Remediation.. 128

Appendix D. Compilation of Rules-of-Thumb in Handbook ................................. .I45

References ........................................................................................................ 149

iv

DISCLAIMER

The description, methods, and cases discussed in this manuscript are presented solely for educational purposes and are not intended to constitute design or operating guidelines or specifications. While every effort has been made to present current and accurate information, the author (and sponsoring and contributing organizations) assume no liability whatsoever for any loss or damage resulting from use of the material in this manuscript; or for any infringement of patents or violation of any federal, state, or municipal regulations. This manuscript was intended to supplement, but not to replace engineering judgment. Use of the information in these notes is solely at the risk of the reader.

ACKNOWLEDGEMENTS

The idea for the Handbook was conceived by Mr. Ben Bloys of ARC0 Exploration and Production Technology Co. This work is a paean to Mr. Bloys foresight regarding the state of knowledge in hydrate engineering, coupled with intelligence and a magnanimous perspective.

Two others have been fundamental to the project. Mr. Jim Chitwood of Texaco has ensured Deepstar hydrate-related reports (Phases I, II, and IIA) were made available to this project. The power of a multi-company consortium, demonstrated by Deepstar, has provided an invaluable supplement to the manuscript. Dr. John Cayias of Oryx Energy contributed by providing for visits to offshore platforms and by providing travels funds and funds for Mr. Seefeldt, the student worker who aided in production of the figures. Dr. Cayias questions have been very useful in re-thinking and re-stating the concepts summarized in the handbook.

Other contributors who have contributed generously are listed in alphabetical order by company:

Amocos Mssrs. George Shoup and J.J. Xiao provided hydrate plug transient- flow simulation results and they reviewed the preliminary draft.

At ARCO. in addition to Mr. Bloys continuous contributions, Mr. Phil Lynch (ARC0 British Ltd.) kindly provided the most detailed North Sea case study.

British Petroleum contributed heavily through Drs. Carl Argo and Chris Osborne (Sunbury) and particularly Dr. Tony Edwards (Dimlington), who related North Sea commercial operating experiences with new inhibitors.

Chevrons Dr. Pat Shuler generously contributed his spreadsheet program HYDCALC to determine inhibition amounts, and he provided access to offshore engineers. Dr. Carl Gerdes reviewed the guidelines for safety, design, and operation.

Conocos Mr. Stan Swearingen and Mobils Mr. Barry Ho&ran were helpful in reviewing both guidelines and manuscript drafts.

V

At Phillips Dr. Bill Parrish provided a hydrate perspective gamed over a quarter century of research and plant optimization. Dr. Parriss collaboration provided an essential bridge between the theoretical and industrial perspectives.

At Statoils Research Center in Trondheim, the Hydrate Team composed of Drs. T. Austvik (leader), L.-H. Gjertsen, 0. Urdahl and A. Lund (SINTEF) provided two fin1 days of interviews regarding hydrate prevention and remediation in the Norwegian sector of the North Sea.

At Texaco, in addition to Mr. Chitwoods tie-in with Deepstar, Dr. Phil Notz has been a hydrate colleague for over a decade, and he provided information on inhibitor economics, feedback on guidelines, and reviewed the draft of the manuscript. Mr Jack Todd at Texaco was extremely helpful in providing the Texaco Reliability Engineering Manual for operating personnel, and in arranging interview with Texaco offshore engineers.

The efforts of the above personnel have contributed in an essential way to this handbook. Their efforts have been an invaluable supplement in moving the handbook toward industrial utility.

This handbook is limited by a personal perspective, intended to assimilate and synthesize the above contributions and those in the literature. The readers constructive critiques are solicited with the goal of improving subsequent revisions.

vi

1Introduction

Natural gas hydrates are crystals formed by water with natural gases andassociated liquids, in a ratio of 85 mole % water to 15% hydrocarbons. Thehydrocarbons are encaged in ice-like solids which do not flow, but rapidly grow andagglomerate to sizes which can block flow lines. Hydrates can form anywhere andanytime that hydrocarbons and water are present at the right temperature and pressure,such as in wells, flow lines, or valves and meter discharges. Appendix A gives hydratecrystal details at the molecular level, along with similarities and differences from ice.

The low temperatures and high pressures of the deepwater environment causehydrate formation, as a function of gas and water composition. In a pipeline, hydratemasses usually form at the hydrocarbon-water interface, and accumulate as flowpushes them downstream. The resulting porous hydrate plugs have the unusual abilityto transmit some degree of gas pressure, while they act as a flow hindrance. Both gasand liquid can frequently be transmitted through the plug; however, lower viscosityand surface tension favors the flow of gas. Depressurization of pipelines is theprincipal offshore tool for hydrate plug removal; depressurization sometimes preventsnormal production for weeks.

This handbook was written to provide the offshore facilities/design engineerwith practical answers to the following four questions:

What are the safety problems associated with hydrates? (Section I) What are the best methods to prevent hydrates? (Section II) How are hydrate plugs best removed? (Section III) What are the economics for prevention and remediation? (Section IV)

Field case studies, pictures, diagrams, and example calculations are the basisfor this handbook. Less pressing questions regarding hydrate structures, plugformation mechanism, etc. are considered as background material in Appendix A. Acomputer program disk and Users Guide (Appendix B) are provided to enableprediction of hydrate conditions. Appendix C is a compilation of Case Studies not inthe handbook body. A Russian hydrate perspective is presented in Makogons (1981,1997) books. An in-depth, theoretical hydrate treatment is given by Sloan (1998).

I. Safety First: A Gallon of Prevention is Worth a Mile of Cure

There are many examples of line rupture, sometimes accompanied by loss oflife, attributed to the formation of hydrate plugs. Hydrate safety problems are causedby three characteristics:

1. Hydrate densities are like that of ice; a dislodged hydrate plug can be a projectilewith high velocities. In the 1997 DeepStar Wyoming field tests, plugs ranged from

225-200 ft. with velocities between 60-270 ft/s. Such velocities and masses provideenough momentum to cause two types of failure at a pipeline restriction (orifice),obstruction (flange or valve), or sharp change in direction (bend, elbow, or tee) asshown in Figure 1. First, hydrate impact can fracture pipe, and second, extremecompression of gas can cause pipe rupture downstream of the hydrate path.

2. Hydrates can form either single or multiple plugs, with no method to predict whichwill occur. High differential pressures can be trapped between plugs, even whenthe discharge end of plugs are depressurized.

3. Hydrates contain as much as 180 volumes (STP) of gas per volume of hydrate.When hydrate plugs are dissociated by heating, any confinement causes rapid gaspressure increases. However, hydrate plug heating is not an offshore option due tothe difficulty of locating the plug and economics of heating a submerged pipeline.

Field engineers discuss the hail-on-a-tin-roof sounds when small hydrateparticles hit a pipe wall. Such small, mobile particles can accumulate to large massesoccupying a considerable volume, often filling the pipeline to tens or hundreds of feetin length. Attempts to blow the plug out of the line by increasing upstream pressure(see Rule-of-Thumb 18) will result in additional hydrate formation and perhapspipeline rupture.

When a plug is depressurized using a high differential pressure, the dislodgedplug can be a dangerous projectile which can cause pipeline damage, as the belowthree case studies (from Mobils Kent and Coolen, 1992) indicate.

_____________________________________________________________________Case Study 1. 1991 Chevron Incident.

A foreman and an operator were attempting to clear a hydrate plug in a sourgas flowline. They had bled down the pressure in the distant end from the wellhead.They were standing near the line when the line failed, probably from the impact of amoving hydrate mass. A large piece of pipe struck the foreman and the operatorsummoned help. An air ambulance was deployed; however the foreman was declareddead on arrival at the hospital. No pre-existing pipe defects were found._____________________________________________________________________

_____________________________________________________________________Case Study 2. 1991 Gulf Incident

On January 10, 1991 the Rimbey gas plant was in the start-up mode. Ahydrate or ice plug formed in the overhead line from the amine contactor. The linehad been depressured to the flare system, downstream of the plug. The ambienttemperature which had been -30oC, rose rapidly due to warming winds aroundmidnight. At 2:00 a.m. the overhead line came apart, killing the chief operator. Inaddition, approximately $6 million damage was suffered by the plant.

A hydrate plug moves down a flowlineat very high velocites.

Where the pipe bends, the hydrate plug can rupturethe flowline through projectile impact.

A hydrate plug movesdown a flowline at veryhigh velocites.

Closed Valve Closed ValveIf the velocity is high enough, themomentum of the plug can cause pressures large enough to rupture the flowline.

Figure 1 - Safety Hazards of Moving Hydrate Plugs(From Chevron Canada Resources, 1992)

1b)

1a)

3Contributing to this failure were pre-existing cracks in the pipeline. Thesecracks did not impair the pipings pressure-containing ability under steady-stateconditions, but they did reduce the piping strength under the transient (impact)conditions when the plug broke free._____________________________________________________________________

_____________________________________________________________________Case Study 3. 1991 Mobil Incident

At 11:30 a.m. on January 2, 1991 two operators attempted to remove ablockage in a sour gas flowline, which had been plugged about three days. Thedownstream side of the plug had been completely depressured. The upstream portionof the line, originally at 1,100 psig, was completely depressured to a truck within a 5minute period. At 12:15 p.m. the flowline failed and gas began flowing fromsomewhere around the casing. The leak was isolated at 3:18 p.m. by an employee of awell-control/firefighting company.

The failure was caused by the eruption of a hydrate plug at a Schedule 40, 3inch, screwed pipe nipple. Note that, because both ends of the hydrate plug weredepressured, there may have been two end plugs, with intermediate plugs or pressureas shown in Figure 2a._____________________________________________________________________

In the above three case studies several common equipment circumstancesexisted. The systems:

1. Were out-of-service immediately prior to the incident.2. Did not have hydrate or freeze protection.3. Were pressurized while out-of-service.4. Were being restarted.5. Had high differential pressures across plugs for short periods.

The Chevron Canada Resources Hydrate Handling Guidelines (1992) suggestthat the danger of line failure due to hydrate plug(s) is more prevalent when:

long lengths of pressurized gas are trapped upstream, low downstream pressures provide less cushion between a plug and

restriction, and restrictions/bends exist downstream of the plug.

_____________________________________________________________________Case Study 4. 1980s Statoil Incident

In the mid-1980s a hydrate plug occurred topside on a platform in a Statoil oilField in the Norwegian sector of the North Sea. The line section was valved-off andheat was applied to remove the plug. After some time of heating, the work crew went

Figure 2 - Safety Hazards of High Pressures Trapped by Hydrates(From Chevron Canada Resources, 1992)

Heat Addition

Hydrate Plug

Hydrate Plug

Gas

Gas

Pipeline Rupture

Low Pressure Low PressureHigh Pressure

HydratePlug

HydratePlug

WELLHEAD SATELLITE

2a)

2b)

4to lunch, intending to complete the task on their return. Upon their return the crewfound that the section of line had exploded during their absence.

Heat had apparently been applied to the mid-point of hydrate plug and theplug-end portions served to contain very high pressures until the line ruptured. Figure2b is a schematic of such a situation. In Section II it is shown that pressure increasesexponentially with temperature increases when hydrates are dissociated._____________________________________________________________________

_____________________________________________________________________Case Study 5. 1970s Elf Incident

In the 1970s a plug occurred on a floating platform riser in the North Sea.Blocking valves were closed and the pipeline was disconnected downstream of theplug. The discharge end of the pipeline was aimed overboard, with the intent of usinghigh upstream pressure to extrude the plug from the line. When the plug was expelledinto the ocean, the force was so great that the platform was said to rise 20 cm in theocean._____________________________________________________________________

The Canadian Association of Petroleum Producers Hydrate Guidelines (1994)suggest three safety concerns in dealing with hydrate blockages:

Always assume multiple hydrate plugs; there may be pressure between the plugs. Attempting to move ice (hydrate) plugs can rupture pipes and vessels. While heating a plug is not normally an option for a subsea hydrate, any heating

should always be done from the end of a plug, rather than heating the plug middle.

The last recommendation could be expanded in consideration of a subsea line: Heating a subsea plug is not recommended due to the inability to determine the

end of the plug as well as provide for gas expansion on plug heating, and Depressuring a plug gradually from both ends is recommended.

The above case studies warn that hydrates can be hazardous to health and toequipment. Yet hydrate plugs can be safely dissociated through the procedureindicated in the Remediation Section (III) of this handbook.

The preferred procedure, from both safety and economic considerations, is toprevent the formation of hydrate plugs, through design and operating practices. Whilethe usage of many gallons of inhibitors may be costly on a continuous basis, suchexpenses are easily overshadowed when plugs form and production is stopped. As thecase studies in this handbook show, it is not uncommon for several hundred yards ofhydrate plugs to form, preventing offshore production for a matter of weeks ormonths, during remediation.

5II. Prevention by Design: How to Ensure Hydrates Wont Form

The purpose of the prevention section is (1) to indicate common offshore sitesof hydrate formation, (2) to indicate design methods to provide hydrate protection,and (3) to provide designs to make remediation easier if a hydrate plug occurs.

Three conditions are required for hydrate formation in offshore processes:

a) Free water and natural gas are needed. Gas molecules ranging in size frommethane to butane are typical hydrate components, including CO2, N2, and H2S.The water in hydrates can come from free water produced from the reservoir, orfrom water condensed by cooling the gas phase. Usually the pipeline residencetime is insufficient for hydrates to form either from water vaporized into the gas,or from gas dissolved in the liquid water.

b) Low temperatures are normally witnessed in hydrate formation; yet, while hydratesare 85 mole % water, the system temperature need not be below 32oF for hydratesto occur. Below about 3000 feet of water depth, the ocean bottom (mudline)temperature is remarkably uniform at 38-40oF and pipelined gas readily cools tothis temperature within a few miles of the wellhead. Hydrates can easily form at38-40oF as well as the higher temperatures of shallower water, at high pressure.

c) High pressures commonly cause hydrate formation. At 38oF, common naturalgases form hydrates at pressures as low as 100 psig; at 1500 psig, common gasesform hydrates at 66oF. Since pipelines typically operate at higher pressures,hydrate prevention should be a primary consideration.

The above three hydrate requirements lead to four classical thermodynamicprevention methods:

1. Water removal provides the best protection. Free water is removed throughseparation, and water dissolved in the gas is removed by drying with tri-ethyleneglycol to obtain water contents less than 7 lbm/MMscf. Water removal processingis difficult and costly between the wellhead and the platform so other preventionschemes must be used.

2. Maintaining high temperatures keeps the system in the hydrate-free region (seeSection II.G.4). High reservoir fluid temperature may be retained throughinsulation and pipe bundling, or additional heat may be input via hot fluids orelectrical heating, although this is not economical in many cases.

3. The system may be decreased below hydrate formation pressure. This leads to theconcept of designing system pressure drops at high temperature points (e.g.bottom-hole chokes). However, the resulting lower density will decrease pipelineefficiency.

4. Most frequently hydrate prevention means injecting an inhibitor such as methanol(MeOH) or mono-ethylene glycol (MEG), which decreases the hydrate formationtemperature below the operating temperature.

6Two kinetic means of hydrate inhibition have been added to thethermodynamic inhibitor list and are being brought into common practice:

5. Kinetic inhibitors are low molecular weight polymers and small moleculesdissolved in a carrier solvent and injected into the water phase in pipelines. Theseinhibitors work by bonding to the hydrate surface and preventing crystal nucleationand growth for a period longer than the free water residence time in a pipeline.Water is then removed at a platform or onshore.

6. Anti-agglomerants are surfactants which cause the water phase to be suspended assmall droplets in the oil or condensate. When the suspended water dropletsconvert to hydrates, the flow characteristics are maintained without blockage.Alternatively the surfactant may transport micro-crystals of hydrate into thecondensed phase. The emulsion is broken and water is removed onshore or at aplatform.

The above methods are used individually or jointly for prevention. Theprevention section of this handbook provides a method to use the six above methodsto prevent hydrates in the design of an offshore system.

Hydrates form in offshore systems in two fundamental ways: (a) slow coolingof a fluid as in a pipeline (see Example 2 below) or (b) rapid cooling caused bydepressurization across valves as on a platform (see Example 3).

Section II.A. provides typical offshore system examples of hydrate formationin a well, a flowline, and a platform. Offshore design for hydrate thermodynamicinhibition with slow cooling of a pipeline is the topic of Sections II.B, C, D, and E.Design practices are provided in Section II.F for hydrate prevention with rapid coolingacross a restriction like a valve. Section II.G gives procedures for prevention ofhydrates through inhibition and heat management. Section II.H. provides generaldesign guidelines for hydrate prevention in an offshore system.

II.A. Where Do Hydrates Form in Offshore Systems?

Figure 3 shows a simplified offshore process between the well inlet and theplatform export discharge where virtually all hydrate problems occur. In the figurehydrate blockages are shown in susceptible portions of the system: (a) the well, (b) thepipeline, or (c) the platform, and this section provides a brief description of each inExamples 1, 2, and 3, respectively,. Prior to the well, high reservoir temperaturesprevent hydrate formation, and after the platform export lines have dry gas andoil/condensate with insufficient water to form hydrates.

In Figure 3, two unusual aspects of the system should be noted: (1) the waterdepth is shown as 6,000 ft. but it may range to 10,000 ft., and (2) the distance betweenthe well and the platform may range to 60 miles. Such depths and distances provide

Figure 3 - Offshore Well, Transport Pipeline, and Platform

Downhole SafetyValve

Well withX-Mas Tree

Riser

SEP.

CO

MP.

DR

Y

Export

Flowline

Transport Pipeline(2-60 miles in length)

Platform

Bulge from Expansionor Topography

Ocean

Mudline

Blockage inRiser

Blockage inFlowline

Blockage in Tree,Manifold, Well

- Depth 6000 ft

7cooling for the pipeline fluids to low temperatures which are well within the hydratestability region.

The system temperature and pressure at the point of hydrate formation must bewithin the hydrate stability region, as determined by the methods of Sections II.Bthrough II.D. The system temperature and pressure enters into the hydrate formationregion, either through a normal cooling process (Example 2 and Figures 6 and 7) orthrough a Joule-Thomson process (Section II.F).

A typical plot of the water temperature in the Gulf of Mexico is shown inFigure 4 as a function of water depth. The plot shows a high temperature of 70oF (ormore) occurs for the first 250 ft. of depth. However, when the depth exceeds 3,000 ft.the bottom water temperature is very uniform at about 40oF, no matter how high thetemperature is at the air-water surface. This remarkably uniform water temperature atdepths greater than 3,000 ft. occurs in almost all of the earths oceans, (caused by thewater density inversion) except in a few cases with cold subsea currents.

The ocean acts as a heat sink for any gas or oil produced so that, withoutinsulation or other heat control methods, any flowline fluid cools to within a fewdegrees of 40oF, no further than a few miles of the wellhead. The rate of cooling withlength is a function of the initial reservoir temperature, the flow rate, the pipelinediameter, and other fluid flow and heat transfer factors. However, as shown in SectionII.B, the ocean bottom temperature of 40oF is low enough to cause hydrates to form atany typical pipeline pressure.

_____________________________________________________________________Example 1. Hydrate Formation in a Well. Figure 5 shows a typical subsea well inwhich fluids are produced through the wing valve and choke to the pipeline. Apressure indication just beyond the choke is essential to determination of hydrateformation in the connecting flowline. About 300-500 ft. below the mudline is theDownhole Safety Valve, used as the initial emergency barrier between the reservoirand the production system. At the top of the well are Swab Valves, which provide anentry way for lubricating hydrate dissociation tools (inhibitor injection, heaters, coiledtubing, etc.) into the well to reach any hydrate blockage.

Hydrate formation in wells is an abnormal occurrence, arising during drilling ofthe well or shut-in/start-up of the well. Normal well-testing procedures will notpromote hydrate formation. Hydrates form only in unusual circumstances, such aspressurizing the well with water or with an aqueous acid solution. Addressing theseblockages should be done using the techniques in the Remediation Section (III). CaseStudies 11 (Section III.B.2.a) and 16 (Section III.C.3) provide two experiences withhydrate formation in a well.

Davalath and Barker (1993) provide a comprehensive set of conditions fordealing with hydrates in deepwater production and testing, including two case studies

Figure 4 - Water Temperature vs. Depth(Gulf of Mexico)

10

100

1000

1000020 30 40 50 60 70 80

Temperature (oF)

Oce

an D

epth

(fe

et)

9 5/8 inch

13 3/8 inch

20 inch

30 inch

ChristmasTree

Wellhead

DownholeCompletion

Mudline

Swab Valve

Master Valve

Downhole Safety Valve

Crossover Valve

Wing Valve

Figure 5 - Typical Subsea Well

8of problems (summarized in Appendix C Case Studies C.23 and C.24) and four casestudies of successful hydrate management. Typically methanol injection capability isprovided in the well at two places: (1) at the subsea tree, and (2) downhole severalthousand feet below the seafloor. The injection location and amount of methanolinjection are specified using the procedure indicated in Section II.G.1.a on methanolinjection.

In offshore well drilling, frequently a water-based drilling fluid is used that canform hydrates and plug blow-out preventors, kill lines, etc. when a gas bubble (orkick) comes into the drilling apparatus. This represents a potentially dangeroussituation for well control. Hydrate formation on drilling is an area of active researchwith several joint industrial projects underway. While a brief overview is given here,the reader is referred to Sloan (1998, Section 8.3.2) for a detailed discussion.

Barker indicated the following rules-of-thumb used by Exxon in consideringhydrate formation with drilling fluids.

Drilling hydrate problems frequently occur, but have only been recognized inrecent years. When hydrates form solids, they remove water from the mud, leaving a solidbarite plug. One should not design a well to operate outside the hydrate region only if flowconditions are maintained. If the well will be in the hydrate formation region atstatic conditions, flow will stop at some period and the well operation will bejeopardized. Several hours may be required for hydrate formation and blockage to occur. As of October 1988 Exxon used salt at the saturation limit range of 150 to 170g/l to prevent hydrate formation. As general guidelines concerning hydrate formation at various water depths,the summary given below by Barker may be used:

Guidelines for Deepwater Hydrate Formation in Drilling Muds in Water-Based Muds

Water Depth (ft.) Risk of Hydrate Formation Problems

9average of more than one gas kick per well, which signaled the possibility of hydrateformation. Only one instance in 2900 ft. of water involved the possibility of hydrateformation, when Shell experienced difficulty disconnecting the drill stack.

Barker and Gomez (1989) documented two occurrences (see Case StudiesC.21 and C.22 of Appendix C) of hydrate formation in relatively shallow waters offCalifornia and the Gulf of Mexico, where losses in drill times were 70 days and 50days, respectively. Recently the number of hydrate problems have increaseddramatically as drilling has moved to deeper water. In several cases where safety wasan issue (plugged blow out preventers, stack connectors, etc.) the well wasabandoned. Much remains to be done in this area._____________________________________________________________________

Downstream of the well and choke, the fluid flows through a pipeline ofconsiderable length before reaching the platform. Example 2 represents flowconditions in the pipeline._____________________________________________________________________Example 2: Hydrate formation in a Flowline. Texacos Notz, (1994) provided ahydrate pipeline case in Figure 6 for a Gulf of Mexico gas. To the right of the diagramhydrates will not form and the system will exist in the fluid (hydrocarbon and water)region. However, hydrates will form in the shaded region to the left of the diagram,and hydrate prevention measures should be taken.

Pipeline pressure and temperature conditions were predicted using a pipeprediction program such as OLGA or PIPEPHASE and those conditions are shownsuperimposed on the hydrate conditions in Figure 6. At low pipeline distances (e.g. 7miles) the flowing stream retains a high temperature from the hot reservoir gas at thepipeline entrance. The ocean cools the system, and at about 9 miles a unit mass offlowing gas and associated water enters the hydrate region (shaded region to the leftof the line marked 0% MeOH), remaining in the uninhibited hydrate area until mile 45.Such a distance may represent several days of residence time for the water phase, sothat hydrates would undoubtedly form, were not inhibition steps taken.

In Figure 6, by mile 25 the temperature of the pipeline system is within a fewdegrees of the ocean floor temperature, so that approximately 23 wt% methanol isrequired in the free water phase to prevent hydrate formation and subsequent pipelineblockage. Methanol injection facilities are not available at the needed point along thepipeline. Instead methanol is injected into the pipeline at the subsea well-head. In thecase of the pipeline shown in Figure 6 methanol is injected at the wellhead so that inexcess of 23 wt% methanol will be present in the free water phase over the entirepipeline length.

As vaporized methanol flows along the pipeline in Figure 6, it dissolves intoany produced brine or water condensed from the gas. Hydrate inhibition occurs in thefree water, usually at accumulations with some change in geometry (e.g., a bend or

2500

2000

1500

1000

500

030 40 50 60 70 80

30%MeOH

20%MeOH

10%MeOH

HydrateFormationCurve

HydrateFormingRegion

7 Miles101520

25

30

3540

4550

Temperature(oF)

Pre

ssur

e(ps

ia)

Figure 6 - Offshore Pipeline Plotted on Hydrate Formation Curves(From Notz, 1994)

HydrateFree Region

10

pipeline dip along an ocean floor depression) or some nucleation site (e.g., sand, weldslag, etc.).

Hydrate inhibition occurs in the aqueous liquid, rather than in the vapor orcondensate. While most of the methanol dissolves in the water phase, a significantamount of methanol either remains with the vapor or dissolves into any liquidhydrocarbon phase present as calculated using the methods shown later in this section.

In Figure 6 Notz showed that the gas temperature increases from mile 30 tomile 45 with warmer (shallower) water conditions. From mile 45 to mile 50 however,a second cooling trend is observed due to a Joule-Thomson gas expansion effect.Methanol exiting the pipeline in the vapor, aqueous, and condensate phases is usuallynot recovered, due to the expense of regeneration._____________________________________________________________________

Todd (1997) provided simulations with a different behavior from the pipelinein Figure 6. In Todds simulations, typical gas pipeline pressure drops are smallrelative to the overall pressure, resulting in an almost constant pressure cooling,providing a straight, horizontal line between the pipeline end points on a plot likeFigure 7. Pipeline pressure drops are functions of several variables, and individualsystems should be simulated for best results.

_____________________________________________________________________Example 3: Typical Offshore Platform Process. Manning and Thompson (1991, pp.80-82, 344-355) detail a typical offshore platform process for a sweet crude oil withdissolved gas delivered to the platform at 1000 psig and 120oF. The process is shownin Figure 8 with process conditions given in Table 1 and selected stream compositionsprovided in Table 2.

The process was sized for a product of 100,000 barrels per day (bpd) of oil tothe pipeline at the LACT (lease automatic custody transfer) unit, with 49 MMscf/d gasproduced at 1000 psig and an overall gas to oil ratio (GOR) of 491 scf/Bsto. Theheavy ends of the crude are divided into five boiling-point cuts while mole fractions ofindividual gas components are given.

There are three objectives of the platform process:

1. to separate the gas, water, and oil, providing an oil phase which has a very lowvapor pressure, and providing water discharge to the ocean.

2. to dehydrate the gas to a water content below 7 lbm/MMscf before injection intothe pipeline to shore, and

3. to compress the gas for transport to land.

Figure 7 - Typical Transport Pipeline Plotted on Hydrate Formation Curves

(From Todd, 1997)

0

500

1000

1500

2000

2500

3000

30 35 40 45 50 55 60 65 70 75Temperature(oF)

Pre

ssu

re(p

sia)

Separator Wellhead

HydrateFormationCurve

10% MeOH

Pipeline

Figure 8 - Typical Offshore Pbtform Schematic (From Manning and Thompson, 1991)

-u Main oil punp

Table 1 - Platform Processing Conditions

(From Manning and Thompson, 1991)

Location Pressure(PSIA) Temperature(oF) Mol/Hr Mol Wt Frac. Vap BPD @60F

1 1019.7 120 12297.76 105.9 0.1821 0

2 1019.7 120 2238.98 18.79 1 0

3 1019.7 120 10058.78 125.29 0 111807.9

4 314.7 115.86 10058.78 125.29 0.2026 0

5 314.7 115.86 2038.13 20.39 1 0

6 314.7 115.86 8020.65 151.94 0 104667.3

7 69.7 111.45 8020.65 151.94 0.1084 0

8 69.7 111.45 869.66 27.44 1 0

9 69.7 111.45 7150.99 167.09 0 101141.7

10 16.7 106.22 7150.99 167.09 0.0664 0

11 16.7 106.22 474.67 43.13 1 0

12 16.7 106.22 6676.32 175.9 0 98533.16

13 74.7 236.54 474.67 74.7 1 0

14 69.7 100 474.67 69.7 0.9464 0

15 69.7 100 449.21 69.7 1 0

16 69.7 100 25.47 69.7 0 199.99

17 69.7 106.27 1318.87 32.2 1 0

18 319.7 280.91 1318.87 32.2 1 0

19 314.7 100 1318.87 32.2 0.8655 0

20 314.7 100 1141.54 28.83 1 0

21 314.7 100 177.32 53.89 0 1172.6

22 314.7 107.94 3179.67 23.42 1 0

23 1024.7 285.05 3179.66 23.42 1 0

24 1019.7 100 3179.66 23.42 0.9926 0

25 1019.7 100 3156.23 23.27 1 0

26 1019.7 100 23.43 43.18 0 144.6

27 1019.7 104.9 5395.21 21.41 1 0

28 314.7 95.43 200.75 52.64 0.0504 0

29 314.7 97.93 226.22 54.96 0.0275 0

30 314.7 104.75 6902.53 171.93 0 100000.1

Table 2 - Gas and Liquid Compositions on Platform(From Manning and Thomson, 1991)

#1 #2 #3 #5 #6 #8 #9 #11 #12 #14 #15

Gas Out Liq. Out Gas Out Liq. Out Gas Out Liq. Out Gas Out Liq. Out 5th Sep. Gas Out

Inlet Fluid 1st Sep. 1st Sep. 2nd Sep. 2nd Sep. 3rd Sep. 3rd Sep. 3rd Sep. 4th Sep. Inlet 6th Sep.

Comp.(Mol Frac.)

Nitrogen 0.0078 0.0287 0.0031 0.0137 0.0005 0.0040 0.0000 0.0004 0.0000 0.0004 0.0005

CO2 0.0005 0.0009 0.0004 0.0012 0.0002 0.0015 0.0001 0.0009 0.0000 0.0009 0.0009

Methane 0.3386 0.8705 0.2202 0.8074 0.0710 0.5605 0.0115 0.1615 0.0008 0.1615 0.1704

Ethane 0.0563 0.0607 0.0553 0.1060 0.0424 0.2118 0.0219 0.2399 0.0063 0.2399 0.2517

Propane 0.0440 0.0213 0.0491 0.0416 0.0510 0.1232 0.0422 0.2789 0.0253 0.2789 0.2880

i-butane 0.0121 0.0033 0.0140 0.0062 0.0160 0.0203 0.0155 0.0597 0.0124 0.0597 0.0598

n-butane 0.0342 0.0073 0.0402 0.0133 0.0470 0.0444 0.0474 0.1393 0.0408 0.1393 0.1371

i-pentane 0.0185 0.0022 0.0221 0.0036 0.0269 0.0118 0.0287 0.0407 0.0278 0.0407 0.0368

n-pentane 0.0244 0.0023 0.0293 0.0036 0.0359 0.0120 0.0388 0.0418 0.0385 0.0418 0.0360

Hexane 0.0429 0.0018 0.0520 0.0024 0.0647 0.0075 0.0716 0.0267 0.0748 0.0267 0.0169

248oF 0.0996 0.0009 0.1216 0.0010 0.1522 0.0027 0.1704 0.0092 0.1819 0.0092 0.0018

340oF 0.0714 0.0001 0.0873 0.0001 0.1094 0.0003 0.1227 0.0008 0.1313 0.0008 0.0000

413oF 0.0611 0.0000 0.0747 0.0000 0.0937 0.0000 0.1051 0.0001 0.1125 0.0001 0.0000

472oF 0.0544 0.0000 0.0665 0.0000 0.0834 0.0000 0.0935 0.0000 0.1002 0.0000 0.0000

657oF 0.1342 0.0000 0.1641 0.0000 0.2058 0.0000 0.2308 0.0000 0.2472 0.0000 0.0000

Total Mol/Hr 12297.75 2238.98 10058.78 2038.13 8020.67 869.66 7150.98 474.66 6676.31 474.66 449.2

#16 #17 #20 #21 #23 #25 #26 #27 #28 #29 #30

Liq. Out 6th Sep. Gas Out Liq. Out 7th Sep. Gas Out Liq. Out Sales Liquid Liquid Sales

Comp.(Mol Frac.) 6th Sep. Inlet 6th Sep. 6th Sep. Inlet 7th Sep. 7th Sep. Gas Line Line Oil

Nitrogen 0.0000 0.002783 0.000467 0.000169 0.009932 0.00999 0.002135 0.017764 0.000398 0.000354 1.3E-05

CO2 0.0000 0.001304 0.000935 0.000395 0.00128 0.001283 0.000854 0.00111 0.000448 0.000398 2.32E-05

Methane 0.0043 0.42762 0.170392 0.061975 0.69145 0.694509 0.279249 0.767528 0.087314 0.077977 0.003338

Ethane 0.0318 0.225381 0.251714 0.125021 0.154435 0.154317 0.170367 0.115474 0.130298 0.119176 0.010048

Propane 0.1190 0.179342 0.288001 0.248351 0.08717 0.086334 0.199829 0.059332 0.242716 0.22876 0.032016

i-butane 0.0562 0.033794 0.05984 0.081205 0.013479 0.013199 0.051238 0.009112 0.077701 0.075325 0.014435

n-butane 0.1783 0.075951 0.137066 0.218463 0.027843 0.027092 0.12895 0.018863 0.207999 0.204668 0.046189

i-pentane 0.1108 0.020328 0.036754 0.086336 0.005897 0.005605 0.04526 0.004178 0.081536 0.084829 0.029695

n-pentane 0.1438 0.020161 0.03602 0.094344 0.005419 0.005098 0.048676 0.003929 0.089057 0.095217 0.040401

Hexane 0.1995 0.010736 0.016941 0.065133 0.002365 0.002091 0.039283 0.00197 0.062111 0.077535 0.074892

248oF 0.1398 0.002404 0.001848 0.017143 0.000654 0.000456 0.027327 0.000649 0.018329 0.032004 0.176941

340oF 0.0145 0.000174 2.23E-05 0.001297 6.6E-05 2.53E-05 0.005551 7.41E-05 0.001793 0.003227 0.12715

413oF 0.0020 2.27E-05 0 0.000169 9.44E-06 0 0.001281 1.3E-05 0.000249 0.000442 0.108848

472oF 0.0000 0 0 0 0 0 0 3.71E-06 4.98E-05 8.84E-05 0.096918

657oF 0.0000 0 0 0 0 0 0 0 0 0 0.239094

Total Mol/Hr 25.46 1318.88 449.2 177.33 3179.65 3156.23 23.42 5395.22 200.77 226.22 6902.57

11

Note that water separation and gas dehydration are vital for hydrateprevention, so that even if the system cools into the hydrate pressure-temperatureregion shown in Figure 7, hydrate formation is prevented due to insufficient water.The export pipeline gas water content is below its water dew point (9 lbm/MMscf) atthe lowest temperature (39oF) so free water will not condense from the gas phase.

The oil is stabilized by flow through a series of four separators, operating at1000psig, 300 psig, 55 psig, and 2 psig before the export oil pipeline, so an oil pipelinepressure greater than 15 psia will prevent a gas phase. Hydrate formation is not asignificant problem in the oil export pipeline because relatively few hydrate formers(nitrogen, methane, ethane, propane, butanes and CO2) are present and the watercontent is low.

The gas from each separator is compressed, cooled, and separated from liquidagain before re-combining the gas with the previous separators gas for injection intothe export gas line. The additional oil obtained after cooling the compressed gasamounts to about 1.5% of the total oil production.

In the process shown, 4310 bhp compressors represent the largest cost on theplatform, with capital cost on the order of $800-$1500 (1990 dollars) per installedhorsepower. These compressors are powered by fuel gas which operates at a lowpressure (about 200 psig), usually fed from the inlet gas passing through a controlvalve with a substantial pressure reduction.

Pressure reductions after the fuel gas takeoff cause cooling, so that point isvery susceptible to hydrate formation, particularly in winter months. Also instrumentgas lines require similar pressure reductions from a header. Texacos Todd et al.(1996. pp. 35-42) observe that when fuel and/or instrument gas lines are blocked dueto hydrates, the process frequently shuts down, resulting in pipeline cooling andsignificant hydrate blockages in the production line at restart.

Hydrate limits to pressure reductions through restrictions such as valves andorifices is shown in Section II.F._____________________________________________________________________

II.B. A One Minute Estimate of Hydrate Formation Conditions (Accurate to 50%)

Assuming the pipeline pressure drop to be relatively small, the engineer may doa rough estimation to determine whether the pipeline will operate in the hydrateregion. As a first approximation, the engineer should first calculate the pressure atwhich hydrates form at the lowest deep ocean temperature (38-40oF), so that if thepipeline pressure is greater, then inhibition might be considered in the pipeline design

12

and operation. Such an approximation may indicate the need for more accuratecalculations to determine the amount of inhibition required.

Rules-of-Thumb. In this handbook, Rules-of-Thumb will frequently be statedin bold type. These Rules-of-Thumb are based upon experience, and they are intendedas guides for the engineer for further action. For example, using a Rule-of-Thumb theengineer might determine that a more accurate calculation was needed for inhibitorinjection amounts, or that further consideration of hydrates was unnecessary. Rules-of-Thumb are not intended to be Absolute Truths, and exceptions can always befound. Where possible the accuracy of each Rule-of-Thumb is provided. The firstRule-of-Thumb is given below for hydrate formation at ocean bottom temperatures.

Rule of Thumb 1: At 39oF, hydrates will form in a natural gas system if freewater is available and the pressure is greater than 166 psig.

Hydrate formation data were averaged for 20 natural gases (from Sloan, 1998,Chapter 6) with an average formation pressure of 181 psia. Of the 20 gases, thelowest formation pressure was 100 psig for a gas with 7 mole % C3H8, while thehighest value was 300 psig for a gas with 1.8 mole % C3H8.

Rule-of-Thumb 1 indicates that most offshore pipeline pressures greatly exceedthe hydrate formation condition, indicating:

gas drying and/or inhibition is needed for ocean pipelines with temperaturesapproaching 39oF,

a more accurate estimation procedure should normally be considered, and hydrate formation pressures are dependent upon the gas composition, and are

particularly sensitive to the amount of propane present. It should be reiterated here that hydrates can form at temperatures in excess of

39oF when the pressure is elevated, as in the case of warmer temperatures in shallowerwater. More accurate estimations of hydrate formation conditions over a broadtemperature range are made by the method in the following section.

II.C. A Ten-Minute Estimation of Hydrate Formation/Inhibition (Accurate to 25%).

As a second approximation of hydrate formation the design/facilities engineershould perform two calculations:

1. A pipeline pressure-temperature flow simulation should be done to determine theconditions between the wellhead and the platform separators, (or between theplatform and the onshore separators), and

13

2. Hydrate formation conditions such as those shown in Figure 6 should becalculated, determining pressures and temperatures of vapor and aqueous liquidinhibited by various amounts (including 0 wt%) of methanol (MeOH) or mono-ethylene glycol (MEG).

The intersection of the above two lines determines the pressure andtemperature at which hydrates will form in a pipeline. As we have seen in Example 2of Section II.A, it is very likely that a long offshore pipeline will have hydrateformation conditions with free water present. The engineer then needs to specify theamount of inhibitor needed to keep the entire pipeline in the fluid region, withouthydrate formation.

Step 1 in this calculation, the flow simulation of the pipeline, is beyond thescope of this handbook and should be considered as a separate, pre-requisite problem,perhaps done by the engineering staff at the home office. As an alternative if a pipeflow simulation is not readily available, the engineer may wish to assume that contentsof a long offshore pipeline will eventually come to the ocean bottom temperature atthe pipeline pressure.

Step 2, enabling estimations of hydrate formation pressures and temperatures,is one of the principal goals of this handbook, as discussed in this and in the followingsection. The below methods (Sections II.C and II.D) may then be used directly todetermine the amount of MeOH (methanol) or MEG (monoethylene glycol) needed toprevent hydrate formation at those conditions.

II.C.1. Hydrate Formation Conditions by the Gas Gravity Method. Thesimplest method to determine the hydrate formation temperature and pressure is viagas gravity, defined as the molecular weight of the gas divided by that of air. In orderto use this chart shown in Figure 9, the gas gravity is calculated and the temperature ofa point in the pipeline is specified. The pressure at which hydrates will form is readdirectly from the chart at the gas gravity and temperature of the line.

To the left of every line hydrates will form from a gas of that gravity, while forpressures and temperatures to the right of the line, the system will be hydrate-free Thefollowing example from the original work by Katz (1945) illustrates chart use.

_____________________________________________________________________Example 4: Calculating Hydrate Formation Conditions Using the Gas Gravity Chart

Find the pressure at which a gas composed of 92.67 mol% methane, 5.29%ethane, 1.38% propane, 0.182% i-butane, 0.338% n-butane, and 0.14% pentane formhydrates with free water at a temperature of 50oF.

Fi ur a - H rat Formati (From Katz 19591

4-

3-

2-

3-

4 J, I I I

6o)oo

I I

35.00 45.00 55.00 65.00 75.00 30.00 40.00 50.00 70.00 80.00 Temperature (F)

14

Solution:The gas gravity is calculated as 0.603 by the procedure below:

Component Mol Fraction Mol Wt Avg Mol Wt in Mix yi MW yiMW

Methane 0.9267 16.043 14.867Ethane 0.0529 30.070 1.591Propane 0.0138 44.097 0.609i-Butane 0.00182 58.124 0.106n-Butane 0.00338 58.124 0.196Pentane 0.0014 72.151 0.101

1.000 17.470

Gas Gravity Mol Wt of GasMol Wt of Air

= = =

17 47028 966

0 603..

.

At 50oF , the hydrate pressure is read as 450 psia_____________________________________________________________________

The user is cautioned that this method is only approximate for several reasons.Figure 9 was generated for gases containing only hydrocarbons, and so should be usedwith caution for those gases with substantial amounts of CO2, H2S, or N2. In addition,the estimated inaccuracies (Sloan, 1985) for the hydrate equilibrium temperature (Teq)and pressure (Peq) are maximized for 0.6 gravity gas as 7oF or 500 psig. In the fiftyyears since the generation of this chart, more hydrate data and prediction methods havecaused the gravity method to be used as a first estimate, whose principle asset is easeof calculation. Section II.D provides one of the most accurate methods for calculationof hydrate conditions, but it requires some additional time as well as a computer.

II.C.2. Estimating the Hydrate Inhibitor Needed in the Free Water Phase Theabove gas gravity chart may be combined with the Hammerschmidt equation toestimate the hydrate depression temperature for several inhibitors in the aqueousliquid:

T C WM(100 - W)=

(1)where:

T = hydrate depression, (Teq - Toper) oF,C = constant for a particular inhibitor (2,335 for MeOH; 2,000 for MEG)W = weight per cent of the inhibitor in the liquid, andM = molecular weight of MeOH (32) or MEG (62).

15

The Hammerschmidt equation was generated in 1934 and has been used todetermine the amount of inhibitor needed to prevent hydrate formation, as indicated inExample 5. The equation was based upon more than 100 natural gas hydratemeasurements with inhibitor concentrations of 5 - 25 wt% in water. The accuracy ofthe Hammerschmidt equation is surprisingly good; tested against 75 data points, theaverage error in T was 5%.

For higher methanol concentrations ( up to 87 wt%) the temperature depressiondue to methanol can be calculated by a modification of Equation (1) by Nielsen andBucklin (1983), where xMeOH is mole fraction methanol in aqueous phase

T = 129 6 1. ln( )xMeOH (1a)

_____________________________________________________________________

Example 5: Methanol Concentration Using the Hammerschmidt Equation.

Estimate the methanol concentration needed to provide hydrate inhibition at450 psia and an ocean floor temperature of 39oF for a gas composed of 92.67 mol%methane, 5.29% ethane, 1.38% propane, 0.182% i-butane, 0.338% n-butane, and0.14% pentane.

Solution:The gas is the same composition and pressure as that in Example 4, with the

gas gravity previously determined to be 0.603 and uninhibited hydrate formationconditions of 50oF and 450 psia. Inhibition is required since the pipeline operates at39oF and 450 psia, well within the hydrate formation region. The weight percent ofinhibitor needed in water phase is determined via the Hammerschmidt Equation (1),with the values:

T = Temperature Depression (50oF - 39oF= 11oF),M = Molecular Weight for Methanol (= 32)C = Constant for Methanol (= 2335)W = Weight Percent Inhibitor

Rearranging in Equation (1)

W = 100 M TM T + C

=

+=

100 32 1132 11 2335

131.

The methanol in the water phase is predicted as 13.1 wt % to provide hydrateinhibition at 450 psia and 39oF for this gas. The engineer may wish to provide anoperational safety factor by the addition of more methanol._____________________________________________________________________

16

II.C.3. Amount of Inhibitor Injected Into Pipeline. While the Hammerschmidtequation enables estimation of the wt% MeOH (or MEG) needed in the free waterphase, three other quantities are necessary to estimate the amount of inhibitor injectedinto the pipeline:

1. the amount of the free water phase,2. the amount of inhibitor lost to the gas phase, and3. the amount of inhibitor lost to the condensate phase.

The amount of the free water phase is multiplied by the wt% inhibitor from theHammerschmidt equation, just as the inhibitor concentrations in the gas andcondensate are multiplied by the flows of the vapor and condensate. Because hydrateinhibition occurs in the water phase, inhibitor concentrations in the gas and condensatephases are usually counted as economic losses. Methanol recovery is done only rarelyon platforms and is typically too expensive at onshore locations.

II.C.3.a Amount of Water Phase The water phase has two sources: (a)produced water and (b) water condensed from the hydrocarbon phases. The amountof produced water can only be determined by data from the well, with an increasingamount of water production over the wells lifetime.

Water condensed from the hydrocarbon phases may be calculated. The watercontent of condensates is usually negligible, but water condensed from gases can besubstantial. The amount of water condensed is the difference in the inlet and outletgas water contents, multiplied by the gas flow rate.

Rule-of-Thumb 2: For long pipelines approaching the ocean bottomtemperature of 39oF, the lowest water content of the outlet gas is given by thebelow table:

Pipe Pressure, psia 500 1000 1500 2000Water Content, lbm/MMscf 15.0 9.0 7.0 5.5

An inlet gas water content analysis is used, if available. Then the water contentof the outlet gas (Rule-of-Thumb 2) may be subtracted from the inlet gas to determinethe water condensed per MMscf of gas. When an inlet gas water content is notavailable a water content chart such as Figure 10 may be used to obtain the watercontent of both the inlet and outlet gas from the pipeline.

In Figure 10 the temperature of the pipeline inlet or outlet is found on the x-axis and water content is read on the y-axis at the pipeline pressure, marked on eachline in Figure 10. The engineer is cautioned not to use the water content chart attemperatures significantly below 38oF. At lower temperatures the actual watercontent deviates from the line due to hydrate formation. An illustration of condensedwater calculation using Figure 8 is given in Example 6 (Section II.C.4).

Figure 10 - Water Formation Curve (From McKetta and Wehe, 1958)

17

II.C.3.b Amount of Inhibitor Lost to the Gas Phase. The Hammerschmidtequation only provides the amount of methanol needed in the free water phase at thepoint of hydrate inhibition, while two other phases represent potential losses ofmethanol. The amount of MeOH or MEG loss into the gas phase should also beconsidered using the following Rules-of-Thumb.

Rule-of-Thumb 3: At 39oF and pressures greater than 1000 psia, the maximumamount of methanol lost to the vapor phase is 1 lbm MeOH/MMscf for everyweight % MeOH in the free water phase.

Rule-of-Thumb 4: At 39oF and pressures greater than 1000 psia, the maximumamount of MEG lost to the gas is 0.002 lbm/MMscf.

The methanol loss chart in Figure 11 shows that at typical offshore pipelineconditions, the amount of methanol in the vapor may be 0.1 mole% of that in thewater phase. Rule-of-Thumb 3 is valid except for low water amounts, when themethanol vapor loss can be substantially higher and the method of Section II.D.3should be used. Figure 12 validates Rule-of-Thumb 4 for MEG. Note that the datafor Figures 11 and 9 were obtained in 1985 for the mole fraction ratio of inhibitor inthe vapor over the aqueous phase; the water phase wt% inhibitor must be converted tomole % in order to use either chart. Example 6 in Section II.C.4 illustrates methanolloss to the gas phase.

II.C.3.c Amount of Inhibitor Lost to the Liquid Phase. Two general Rules-of-Thumb can be applied to inhibitor losses in the condensate.

Rule-of-Thumb 5: Methanol concentration dissolved in condensate is 0.5 wt %.

Rule-of-Thumb 6: The mole fraction of MEG in a liquid hydrocarbon at 39oFand pressures greater than 1000 psia is 0.03% of the water phase mole fractionof MEG.

Even with low losses of MEG relative to MeOH in both the gas and the liquid,it is important to remember that methanol is a much more effective inhibitor thanethylene glycol on a weight basis. The predominance of methanols use is due to thiseffectiveness, together with the fact that methanol easily flows to the point of hydrateformation.

II.C.4. Example Calculation of Amount Methanol Injection. The below samplecalculation uses all of the concepts presented in Section II.C._____________________________________________________________________Example 6: Methanol Injection Rate. A sub-sea pipeline with the below gascomposition has inlet pipeline conditions of 195oF and 1050 psia. The gas flowing

Figure 11 - Methanol Lost to Vapor (From Sloan, 1998)

Temperature, OF

20 30 40 50 60 70 80 90 100

% 1

I t I I I III I, I I, I I I I I I, 1 III I,, 1 I, I,, III,

5 Ls

isobaric Vapor Phase Distribution for Methanol in Hydrate-Foxming Systems

,z - InK,, = a + b[l/T(R)]

a b -3, 0 1000 psia 8.41233 -7250.20 ,- 0 I- 0 2000 psia 6.82227 -6432.23 ,- 6- 0 3000 psia 5.70578 -5738.48 s III 1111,,,,,,,,,,,,,,,,,,,,,,,,,,r

Z.lOE-3 ZOOE-3 1.9oE3 l.mE-3

lfw)

Fimre 12 - Mono-Ethylene Glvcol Lost to Vapor

xx)-

100 =

60 = 40-

20-

IO =

6=

4-

2-

I =

0.6 =

a4 - r

(From Townsend and Reid, 1972)

QOI I /I I 1 I I 1 -40 -20 0 20 40 60 Bo

EOlJlLlBRlUM TEMPERATURE, OF

18

through the pipeline is cooled by the surrounding water to a temperature of 38oF. Thegas also experiences a pressure drop to 950 psia. Gas exits the pipeline at a rate of 3.2MMscf/d. The pipeline produces condensate at a rate of 25 bbl/day, with an averagedensity of 300 lbm/bbl and an average molecular weight of 90 lbm/lbmole. Producedfree water enters the pipeline at a rate of 0.25 bbl/day.

Natural gas composition (mole %): methane = 71.60%, ethane = 4.73%, propane=1.94%, n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen =5.96%.Find the rate of methanol injection needed to prevent hydrates in the pipeline.

Solution:

Basis: The basis for these calculations was chosen as 1 MMscf/d.

Step 1) Calculate Hydrate Formation Conditions using the Gas Gravity Chart

Component Mol Fraction Mol Wt Avg Mol Wt in Mixture yi MW yiMW

Methane 0.7160 16.04 11.487Ethane 0.0473 30.07 1.422Propane 0.0194 44.09 0.855n-Butane 0.0079 58.12 0.459n-Pentane 0.0079 72.15 0.570Nitrogen 0.0596 28.01 1.670Carbon Dioxide 0.1419 44.01 6.245

1.000 22.708

Gas Gravity mol wt gasmol wt air

22.70828.966

0.784= = =

Reading the gas gravity chart (Figure 9), the hydrate temperature is 65oF at 1000 psia.

Step 2) Calculate the Wt% MeOH Needed in the Free Water PhaseThe Hammerschmidt Equation is: T C W

100M - MW=

Where:T = Temperature Depression (65oF - 38oF= 27oF),

M = Molecular Weight for Methanol (= 32.0)

C = Constant for Methanol (= 2335)

W = Weight Percent Inhibitor

19

Rearranging the Hammerschmidt equation

W = 100 M TM T + C

=

+=

100 32 2732 27 2335

27

The weight percent of methanol needed in freewater phase is 27.0% to providehydrate inhibition at 1000 psia and 38oF for this gas.

Step 3) Calculate the Mass of Liquid H2O/MMscf of Natural Gas

- Calculate Mass of Condensed H2OIn the absence of a water analysis, use the water content chart (Figure 10), tocalculate the water in the vapor/MMscf. The inlet gas (at 1050 psia and 195oF)water content is read as 600 lbm/MMscf. Rule of Thumb 2 states that exitinggas at 1000 psia and 39oF contains 9 lbm/MMscf of water in the gas. The massof liquid water due to condensation is:

600 lbm _ 9 lbm = 591 lbmMMscf MMscf MMscf

- Calculate Mass of Produced H2O Flowing into the LineConvert the produced water of 0.25 bbl/day to a basis of lbm/MMscf:

- Total Mass of Water/MMscf Gas: Sum the condensed and produced water

591 lbm + 27.4 lbm = 618.4 lbmMMscf MMscf MMscf

Step 4) Calculate the Rate of Methanol InjectionMethanol will exist in three phases: water, gas, and condensate. The total mass ofmethanol injected into the gas is calculated as follows:

-Calculate Mass of MeOH in the Water Phase27.0 wt% methanol is required to inhibit the free water phase, and the mass ofwater/MMscf was calculated at 618.4 lbm. The mass of MeOH in the freewater phase per MMscf is:

27wt% M lb MeOHM lb MeOH 618.4lb H O

m

m m 2

=

+100%

MMscfOHlb

MMscfday

gallb

bblgal

dayObblH mm 22 4.27

2.3134.84225.0

=

20

Solving M = 228.7 lbm MeOH in the water phase

-Calculate Mass of MeOH Lost to the GasRule of Thumb 3 states that the maximum amount of methanol lost to thevapor phase is 1 lbm MeOH/MMscf for every wt% MeOH in the water phase.Since there is 27 wt% MeOH in the water, that maximum amount of MeOHlost to the gas is 27 lbm/MMscf.

-Calculate the Mass of MeOH Lost to the CondensateRule of Thumb #5 states that the methanol concentration in the condensate willbe 0.5wt%. Since a barrel of hydrocarbon weighs about 300 lbm, the amountof methanol in the condensate will be

0.005 300 lbm/bbl 25bbl/d 1d/3.2 MMscf = 11.7 lbm/MMscf

-Calculate the Total Amount of MeOH/MMscfMeOH in Water = 228.7 lbm/MMscfMeOH in Gas = 27 lbm/MMscfMeOH in Condensate = 11.7 lbm/MMscf

Total MeOH Injection = 267.4 lbm/MMscf(or 40.33 gal/MMscf at a MeOH density of 6.63 lbm/gal)

_____________________________________________________________________

In the above example, the amount of methanol lost to the gas and condensate isapproximately 11% of the total amount injected. However, with large amounts ofcondensate it is not uncommon to have as much as 90% of the injected methanoldissolved in the condensate (primarily) and gas phases. In such cases, the Rules-of-Thumb should be replaced by a more accurate calculation, as shown in section II.D.

The hand calculation example is provided for understanding of the secondapproximation. The method is made much more convenient for the engineer via theuse of the below spreadsheet program.

II.C.5. Computer Program for Second Approximation. Shuler (1997) ofChevron provided a computerized version (HYDCALC) of the above calculationmethod, which is included with the disk in this handbook. Slightly different Rules-of-Thumb have been used, but these differences are insignificant, as shown by acomparison in Section II.C.6 of results of the hand calculation (Example 6) with thecomputer method (Example 7).

21

HYDCALC is an IBM-PC compatible spreadsheet that provides an initialestimate of pipeline methanol injection for hydrate inhibition. To use HYDCALC,obtain access to a Microsoft Excel - Version 7.0 spreadsheet program and copyHYDCALC into a hard drive directory. Start Excel - Version 7.0 and open the fileHYDCALC.

Once the file is opened, the user will see text in three different colors on acolor screen- black, red, and blue. The red text signifies required User Inputs,composed of the following eight pieces of information to start the program:

1) Pipeline Inlet Pressure - Starting high pressure2) Cold Pipeline Pressure - Pressure at the coldest part of the pipeline.3) Pipeline Inlet Temperature - Starting warm temperature.4) Cold Pipeline Temperature - Temperature at the coldest part of the pipeline.5) Gas Gravity - Gas gravity, calculated by the steps in Section II.C.1 and Example 4.6) Gas Flow Rate - Gas flow in the pipeline measured in MMscf/d.7) Condensate Rate - Condensate flow in the pipeline measured in bbl/d.8) Formation Water Rate - Produced water flowing into the pipeline (bbl/d).

Once the above values are input, HYDCALC displays calculations for bothIntermediate Results (in black) and the amount of methanol or glycol to be injected (inblue on a color screen). In the below example, the User Input and Calculations areboth listed in black, due to printing restrictions. A prescription for the use of thismethod is shown in Example 7.

_____________________________________________________________________Example 7. Use of HYDCALC to Find Amount of Methanol and Glycol Injection

This spreadsheet problem is the identical problem worked in Example 6 byhand. A sub-sea pipeline with the a gas gravity of 0.784 has inlet pipeline conditionsof 195oF and 1050 psia. The gas flowing through the pipeline is cooled by thesurrounding water to a temperature of 38oF. The gas also experiences a pressure dropto 950 psia. Gas exits the pipeline at a rate of 3.2 MMscf/d. The pipeline producescondensate at a rate of 25 bbl/d, with an average density of 300 lbm/bbl and an averagemolecular weight of 90 lbm/lbmole. Produced free water enters the pipeline at a rate of0.25 bbl/d.

Determine the rate of methanol and glycol injection needed to prevent hydrateformation in the pipeline.

Solution:

Figure 13 on the next page is a copy of HYDCALC, highlighting the data inputthat is needed to run the program. All required data are provided in the example, with

Figure 13 - Example #6 Calculated by HYDCALC

a:\excel7\hydcalV7.xls disk 2 P.J. Shuler CPTC 5/27/97CTN 694-7572, PJSH

HYDCALC Version 2 for Excel 7.0

INHIBITOR REQUIREMENT CALCULATION InputsFOR A WET GAS FLOWLINE

USER INPUTS (in red)Bottom Hole Pressure 1050 psia .===> starting high pressureCold Line Pressure 950 psia .===> pressure where hydratesBottom Hole Temperature 195 F .===> starting high temperatureCold Temperature 38 F .===> temperature where hydratesGas gravity 0.784Gas Rate 3.2 MMSCFDCondensate Rate 25 bbl/day

Formation Water Rate ?? 0.25 bbl/ H2O/day SUMMARY OF RESULTSCalculated Condensed Water 5.7 bbl/ H2O/dayTotal Water to Treat 5.9 bbl/ H2O/day Methanol Injection Rate 134.9 gal/day

(pure MeOH @ 77F)Methanol Rate/MMSCF 42.2 gal/MMSCF

CALCULATION WORKSHEETWater in hot gas 626.2 lb/MMSCF MEG Injection Rate 190.0 gal/dayWater in cold gas 6.5 lb/MMSCF (pure MEG)WATER CONDENSED 619.8 lb/MMSCF MEG Rate/MMSCF 59.4 gal/MMSCF

Total Water CONDENSED 1983 lb/dayin the line 5.7 bbl H2O/dayTotal water (from above) 5.9 bbl H2O/day

Hydrate temperature of gas 65.0 F Freeze depression required 27.0 F

Wt. percent methanol 27.0 % Summary of Resultsneeded in water phase

wt. percent MEG 45.6 %needed in water phase

Vapor to liquid 0.9162 lb/MMSCFpercomposition ratio % in water

Methanol in gas 24.77 lb/MMSCF MEG in gas 0 lb/MMSCF

Methanol into condensate 37.5 lb/dayMEG into condensate 22.5 lb/day

Methanol to protect 767 lb/daywater phaseMEG to protect 1735 lb/daywater phase

TOTALSMethanol to protect 767 lb/day MEG to protect 1735 lb/daywater phase water phaseMethanol going to gas 79 lb/day MEG in gas 0 lb/MMSCFMethanol into condensate 37.5 lb/day MEG into condensate 22.5 lb/dayTOTAL Methanol Rate 884 lb/day TOTAL MEG Rate 1758 lb/day

Methanol Injection Rate 134.9 gal/day MEG Injection Rate 190.0 gal/day(pure MeOH @ 77F) (pure MEG)Methanol Rate/MMSCF 42.2 gal/MMSCF MEG Rate/MMSCF 59.4 gal/MMSCF

22

the exception of gas gravity. Gas gravity was calculated using the method described inExample 4 to be 0.784. Figure 13 on the next page displays all input data and results.

The amount of methanol injected is 42.2 gal/MMscf and the amount of glycolinjected is 59.4 gal/MMscf._____________________________________________________________________

For ease of use, the engineer will turn to HYDCALC to perform the secondapproximation calculation. The following section provides accuracy and limitations ofboth HYDCALC and the hand calculation methods, which are vital to their use.

II.C.6. Accuracy, Limitations, and Extensions for Second Estimation Method

A comparison of the previous results using the hand calculation method andthe HYDCALC method is included in the below table.

Calculated Quantity Hand Method Resultwith Rules-of-Thumb

HYDCALCResult

Water Condensed, lbm/MMscf 591 619.8MeOH in Water, lbm/MMscf 228.7 239.7MeOH in Gas, lbm/MMscf 27 24.7MeOH in Condensate, lbm/MMscf 11.7 11.7Total MeOH Injection, lbm/MMscf 267.4 276.25Total MeOH Injection, gal/MMscf 40.3 42.2

While the hand calculation and the computer program provide only slightlydifferent results, both include inaccuracies. For example, while it is possible to obtainmore significant figures with HYDCALC than with the charts in the hand method,HYDCALC inaccuracies are those of the charts upon which HYDCALC is based.

Using HYDCALC it was estimated that 27 wt% methanol was required in thewater phase to inhibit the pipeline, while measurements by Robinson and Ng (1986)show that only 20 wt% methanol was required for inhibition at the same gascomposition, temperature, and pressure of Examples 6 and 7.

The major inaccuracies in the second estimation method are in the gas gravityhydrate formation conditions, which are only accurate to 7oF or to 500 psia. TheHammerschmidt equation, the inhibitor temperature depression DT is accurate to 5%. With such inaccuracies, the amount of methanol or glycol injection could be inerror by 100% or more. The principal virtue of the second estimation method is easeof calculation rather than accuracy.

23

A second limitation is that the method was generated for gases without H2S,which represents the case for many gases in the Gulf of Mexico. A modification of thegas gravity method was proposed for sour gases by Baillie and Wichert (1987).

II.D. Most Accurate Calculation of Hydrate Formation and Inhibition.

If the HYDCALC results indicate that hydrate formation will occur withoutinhibition, the engineer should elect to do further, more accurate calculations. Themost accurate method for hydrate formation conditions, together with the amount ofmethanol needed in the water phase, is available as the final estimation technique in acomputer program, HYDOFF. A Users Manual (Appendix B) and an example areprovided with this handbook. The method details are too lengthy to include here; theengineer interested in program details is referred to the hydrate text by Sloan (1998,Chapter 5).

In Section II.D examples are provided for the most accurate methods for thefollowing calculations:

calculation of hydrate formation and inhibition in water (Section II.D.1), conversion of MeOH to MEG concentration in water phase (Section

II.D.2), calculation of solubility of MeOH and MEG in the gas (Section II.D.3),

and calculation of solubility of MeOH and MEG in condensate (Section II.D.4).

II.D.1. Hydrate Formation and Inhibitor Amounts in Water Phase. HYDOFFis an IBM-compatible computer program provided on the disk with this handbook.The program enables the user to determine hydrate formation conditions and theamount of inhibitor needed in the free water phase. As a minimum of a 386-IBMcomputer with 2 megabytes of RAM is required. The program may be executed eitherfrom the Windows or from the DOS environment.

To use the program, first load both HYDOFF.EXE and FEED.DAT from theaccompanying 3.5 inch disk onto a hard drive. Appendix B is a Users Manual withseveral examples of the use of HYDOFF. The simplest (and perhaps the mostbeneficial) use of HYDOFF is illustrated through Example 8.

_____________________________________________________________________Example 8: Use of HYDOFF to Obtain Hydrate Formation and Prevention Conditions.Find (a) the hydrate formation pressure of the below natural gas at 38oF and (b) theamount of methanol in the water phase to inhibit hydrates at 38oF and 1000 psia. The

24

gas composition (mole %) is: methane = 71.60%, ethane = 4.73%, propane = 1.94%,n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen = 5.96%

Solution: The gas in this example has the same composition as the gas in Examples 6and 7, so the results provide a comparison with hand and computer calculations of thegas gravity method (Section II.C.1) and the Hammerschmidt equation (SectionII.C.2).

For convenience with multiple calculations, the reader may wish to edit theprogram FEED.DAT to reflect the gas composition of the problem. Modification ofthe FEED.DAT program is done at the MSDOS prompt, by changing the compositionof each component to that of the example gas, and saving the result using the standardMSDOS editing technique. However it is not necessary to use FEED.DAT; the gascomposition may be input as part of the program HYDOFF.

In the following solution, each input from the user is underlined:

1. From Windows or in the proper directory, click on, or type HYDOFF; press Enter.2. After reading the title screen, press Enter3. At the Units screen, press 1 (to choose oF and psia) then Enter4. At the FEED.DAT question screen, press 2 and Enter if you wish to use the data inFEED.DAT, or 1 and Enter if you wish to enter the gas composition in HYDOFF byhand. The remainder of this example is written assuming that the user will enter thegas composition in HYDOFF rather than use FEED.DAT. The use of FEED.DAT issimpler and should be considered for multiple calculations with the same gas.5. The next screen asks for the number of components present (excluding water).Input 7 and Enter.6. The next screen requests a list of the gas components present, coded by numbersshown on the screen. Input 1, 2, 3, 5, 7, 8, and 9 (in that order, separating the entriesby commas) and then Enter.7. The next series of screens request the input of the mole fractions of each component

Methane 0.7160 Enter.Ethane 0.0473 Enter.Propane 0.0194 Enter.n-Butane 0.0079 Enter.Nitrogen 0.0596 Enter.Carbon Dioxide 0.1419 Enter.n-Pentane 0.0079 Enter.

8. At the Options screen, input 1 then Enter.9. At the screen asking for the required Temperature, input 38, and Enter.10. Read the hydrate formation pressure of 229.7 psia, (meaning hydrates will form atany pressure above 230 psia at 38oF for this gas.)11. When asked for another calculation input 1 for No then Enter.12. At the Options screen input 2, then Enter.

25

13. At the screen asking for the required temperature, input 38, and Enter.14. At the screen to enter the WEIGHT PERCENT of Methanol, input 22.15. Read the resulting hydrate condition of 22 wt% MeOH, 38oF, and 1036 psia.

It may require some trial and error with the use of the program before thecorrect amount of MeOH is input to inhibit the system at the temperature and pressureof the example. One starting place for the trial and error process would be the amountof MeOH predicted by the Hammerschmidt equation (27 wt%) in Example 6. Ng andRobinson (1983) measured 20 wt% of methanol in the water required to inhibithydrates at 38oF and 1000 psia. A comparison of the measured value with thecalculated value (22 wt%) in this example and through the Hammerschmidt equationprovides an indication of both the absolute and relative calculation accuracy.

HYDOFF can also be used to predict the uninhibited hydrate formationtemperature at 1000 psia at 58.5oF, through a similar trial and error process, ascompared with 65oF determined by the gas gravity method. No measurements areavailable for the uninhibited formation conditions of the gas in this example.

In using HYDOFF, if components heavier than n-decane (C10H22) are present,they should be lumped with n-decane, since they are all non-hydrate formers._____________________________________________________________________

II.D.2 Conversion of MeOH to MEG Concentration in Water Phase. Theconcentration of inhibiting monoethylene glycol (MEG) in the water phase can bedetermined from methanol (MeOH) concentration using a simple correlation ofinhibitors:

wt% MEG = -1.209+ 2.34 (wt% MeOH)- 0.052(wt% MeOH) 2+ 0.0008(wt% MeOH)3 (2)

In order to use Equation (2), first determine the amount of methanol requiredusing HYDOFF, as in Example 8. Insert the amount of methanol in Equation (2) todetermine the amount of mono-ethylene glycol needed in water to inhibit hydrates.Equation (2) should be used for the free water phase only. Example 9 (Section II.D.5)provides a summary calculation of all the procedures in Section II.D.

II.D.3. Solubility of MeOH and MEG in the Gas. Figure 11 is a fit of recentmeasurements by Ng and Chen (1995) for KvMeOH defined as the methanol molefraction in gas relative to water ( yMeOH/xMeOH in H2O). Once the mole fraction ofmethanol in water is determined, it may be multiplied by KvMeOH to obtain the molefraction of methanol in the gas. As can be determined by Figure 11, the solubility inthe water is only slightly affected by pressure over the range from 1000-3000 psia atoffshore temperatures. For a conservative estimate the 3000 psia line isrecommended:

26

KvMeOH = exp (5.706 - 5738(1/T(oR)) (3)

Figure 12 provides an estimation of monoethylene glycol dissolved in gas at1000 psig, from the data of Polderman (1958). As indicated in the figure the amountof MEG in the vapor is very small; Ng and Chen (1995) measure a negligible MEGconcentration in the vapor as a comparison. Example 9 (Section II.D.5) provides asummary calculation of all the procedures in Section II.D.

II.D.4. Solubility of MeOH and MEG in the Condensate. Figure 14 is a fit ofmeasurements by Ng and Chen (1995) for KLMeOH defined as the methanol molefraction in condensate relative to water ( xMeOH in HC/xMeOH in H2O). Once the molefraction of methanol in water is determined, it may be multiplied by KLMeOH to obtainthe mole fraction of methanol in the condensate. In Figure 14 all lines are pressureindependent and the toluene line should not apply, due to the absence of suchcompounds in typical condensates. The fit for the solubility of methanol incondensates of methane, propane, and n-heptane is recommended:

KLMeOH = exp (5.90 - 5404.5(1/T(oR)) (4)

Similar measurements by Ng and Chen (1995) are shown in Figure 15 tospecify the solubility for monoethylene glycol (MEG) in the condensate, via KLMEGdefined as the MEG mole fraction in condensate relative to water ( xMEG in HC/xMEG inH2O). Note that the KLMEG values are two orders of magnitude lower than KLMeOHvalues. No pressure dependence is observed, and the line for MEG solubility inmethane, propane, and n-heptane (or methylcyclohexane) is recommended, sincetoluene is not in condensate:

KLMEG = exp (4.20 - 7266.4(1/T(oR)) (5)

Example 9 (Section II.D.5) provides a summary calculation of all theprocedures in Section II.D.

II.D.5. Best Calculation Technique for MeOH or MEG Injection. Thefollowing example is identical that of Examples 6 and 7, with the exception that bothMeOH and MEG injection are calculated for comparison of each inhibitor as well aswith the less accurate method of Section II.C.

_____________________________________________________________________Example 9: Most Accurate Inhibitor Injection Calculation. A sub-sea pipeline withthe below gas composition has inlet pipeline conditions of 195oF and 1050 psia. The

Figure 14 - Methanol Lost to Condensate (From Sloan, 1998)

Temperature (OF) 20 30 40 50 60 70 80 90 100 115 130

1o-~_I1~~~~ 0 s-l 7-

h 6-

zi 3- g 4-

5 -

i -

3 102- u ,- 5 :_

ti I- .-

3-

3-

blK mc= a + b[l/T(R)]

a b -

0 Methane + Propane + n-Hcptane 5.90062 -5404.45

[7 Metime + Propane + htiylcyclohexane 5.91795 -5389.73

0 Methane + Propane + Tolueoe 3.55142 -3242.43

2.1E-3 2.OE-3 1.9E-3

l/T(R) 1.8E-3

Figure 15 - Mono-Ethvlene Glvcol Lost to Condensate (Fmm Sloan, 1998)

Temperature, OF 40 50 60 70 80 90 100

J!,~ 1

InK,= a + b[l/T(Fi)]

a b 0 Mdlmw+Pmpm+ll-~ - - f3 Ibtbw+~+~~e 4A9818 -726638

0 -+Rupm+Tol\rar 2.65872 -5211.86

I I I I I I

12

z.ooE-3 1.9SE-3 MOE-3 Las-3

l/T(R)

1 .SOE-3 1.7s3

27

gas flowing through the pipeline is cooled by the surrounding water to a temperatureof 38oF. The gas also experiences a pressure drop to 950 psia. Gas exits the pipelineat a rate of 3.2 MMscf/d. The pipeline produces condensate at a rate of 25 bbl/d, withan average density of 300 lbm/bbl and an average molecular weight of 90 lbm/lbmole.Produced salt-free water enters the pipeline at a rate of 0.25 bbl/d.

Natural gas composition (mole%): methane = 71.60%, ethane = 4.73%, propane =1.94%, n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen =5.96%

Find the rate of both methanol and monoethylene glycol injection needed to preventhydrate formation in the pipeline.

Solution:

Basis: the basis for solution is 1 MMscf/d.

Step 1) Calculate the Concentration of MeOH and MEG in the Water Phase.

In Example 8 the methanol concentration was calculated to be 22 wt% of thefree water phase at 38oF and 1000 psia. Using Equation (2) the MEG concentrationwas calculated at 33.6 wt% in the water phase.

Step 2) Calculate the Mass of Liquid H2O/MMscf of Natural Gas

- Calculate Mass of Condensed H2OUse the water content chart (Figure 10), to calculate the water in thevapor/MMscf. The inlet gas (at 1050 psia and 195oF) water content is read as600 lbm/MMscf. The outlet gas (at 950 psia and 38oF) water content is read as9 lbm/MMscf. The mass of liquid water due to condensation is:

600 lbm _ 9 lbm = 591 lbmMMscf MMscf MMscf

- Calculate Mass of Produced H2O Flowing into the LineConvert the produced water of 0.25 bbl/d to the basis of lbm/MMscf:

- Total Mass of Water/MMscf Gas: Sum the condensed and produced water591 lbm + 27.4 lbm = 618.4 lbmMMscf MMscf MMscf

MMscfOHlb

MMscfday

gallb

bblgal

dayObblH mm 22 4.27

2.3134.84225.0

=