hydrate handbook
TRANSCRIPT
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 Won’t 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. User’s Guide for HYDOFF and XPAND Programs.. ........................ ,109 B.l.HYDOFF.. .................................................................................... .I09 B.2. XF’AND.. ...................................................................................... ,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:
Amoco’s 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.
Chevron’s 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.
Conoco’s Mr. Stan Swearingen and Mobil’s 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. Parris’s collaboration provided an essential bridge between the theoretical and industrial perspectives.
At Statoil’s 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. Chitwood’s 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
1
Introduction
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 User’s 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 Makogon’s (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
2
25-200 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 Mobil’s 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)
3
Contributing to this failure were pre-existing cracks in the pipeline. Thesecracks did not impair the piping’s 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. 1980’s Statoil Incident
In the mid-1980’s 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)
4
to 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. 1970’s Elf Incident
In the 1970’s 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.
5
II. Prevention by Design: How to Ensure Hydrates Won’t 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.
6
Two 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
7
cooling 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 earth’s 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
8
of 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 (or“kick”) 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<1000 A hydrate problem will probably not occur≤1500 Without inhibition a hydrate problem may occur≤2000 Without inhibition a hydrate problem will occur≥3000 Insufficient experience; salt alone will not suffice
By 1988 Shell had drilled 16 wells in the Gulf of Mexico at water depthsbetween 2,000 and 7,500 feet, using muds with 20 wt% sodium chloride (NaCl) andpartially hydrolyzed polyacrylamide (PHPA). In each well Shell experienced an
9
average 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. Texaco’s 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 Todd’s 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 separator’s 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. Texaco’s 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 yi•MW
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 GravityMol Wt of Gas
Mol Wt of Air= = =17 470
28 9660 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:
∆TC W
M(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 T
M T + C
∆∆
= × ×× +
=100 32 11
32 11 2335131.
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 well’s 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 methanol’s 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 yi•MW
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 Gravitymol wt gas
mol wt air
22.708
28.9660.784= = =
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 Phase
The Hammerschmidt Equation is: ∆TC 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 T
M T + C
∆∆
= × ×× +
=100 32 27
32 27 233527
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 lbm
MMscf 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 lbm
MMscf 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 MeOH
M lb MeOH 618.4lb H Om
m m 2
=+
×100%
MMscf
OHlb
MMscf
day
gal
lb
bbl
gal
day
ObblH mm 22 4.272.3
134.84225.0=
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 ∆T 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 User’s 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 User’s 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 Kv
MeOH 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 Kv
MeOH 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 KL
MeOH 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 KL
MeOH 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 KL
MEG
defined as the MEG mole fraction in condensate relative to water (≡ xMEG in HC/xMEG in
H2O). Note that the KLMEG values are two orders of magnitude lower than KL
MeOH
values. 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-~_I’1’~““““““““‘~“““““~“““‘~ 0 s-l 7-
h 6-
zi 3-
g 4-
5 ‘-
i ‘-
3 10‘2- 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 I’btbw+~+~~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 lbm
MMscf 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 lbm
MMscf MMscf MMscf
MMscf
OHlb
MMscf
day
gal
lb
bbl
gal
day
ObblH mm 22 4.272.3
134.84225.0 =
28
Step 4) Calculate the Rate of Methanol and MEG InjectionMeOH and MEG can exist in three phases: water, gas, and condensate. The
total masses of MeOH and MEG injected per MMscf are calculated as follows:
-Calculate Amount of (a) MeOH and (b) MEG in the Water Phase(a) 22.0 wt% methanol is required to inhibit the free water phase, and the massof water/MMscf was calculated at 618.4 lbm. The mass of MeOH in the freewater phase per MMscf is:
22wt%M lb MeOH
M lb MeOH 618.4lb H Om
m m 2
=+
×100%
Solving M = 174.4 lbm MeOH/MMscf in the water phase
(b) In Step 1 33.6.0 wt% MEG is required to inhibit the free water phase, andthe mass of water/MMscf was calculated at 618.4 lbm in Step 3. The mass ofMEG in the free water phase per MMscf is:
33.6wt%N lb MEG
N lb MEG 618.4lb H Om
m m 2
=+
×100%
Solving N = 313.1 lbm MEG/MMscf in the water phase
-Calculate Amount of (a) MeOH and (b) MEG Lost to the Gas(a) MeOH Lost to Gas. The mole fraction MeOH in the free water phase is:
mole fraction MeOH = 174.4 lb MeOH lb lbmol MeOH)
174.4 / 32 + 618.4lb H O / (18lb / lbmolH O)m m
m 2 m 2
/ ( /32
The mole fraction MeOH in the water phase is xMeOH in H2O = 0.137. Thedistribution constant of MeOH in the gas is calculated at 38oF (497.7oR) byEquation (3), relative to the methanol in the water
KvMeOH = exp (5.706 - 5738×(1/497.7oR) = 0.00296 (3)
where oR = oF + 459.69The mole fraction of MeOH in the vapor is yMeOH = Kv
MeOH•xMeOH in H2O or
yMeOH = 0.00296 × 0.137 = 0.0004055
The daily gas rate is 8432 lbmol (= 3.2 × 106 scf / (379.5 scf/lbmol), where anscf is at 14.7 psia and 60oF), so that the MeOH lost to the gas is 3.42 lbmol (=
29
0.0004055 × 8432) or 109.4 lbm/day. Since the calculation basis is 1 MMscf/d,the amount of MeOH lost is 34.2 lbm/MMscf (= 109.4 lbm / 3.2 MMscf).
(b) MEG Lost to Gas. In Figure 12 use the 50 wt% MEG line to determine theMEG lost to the gas is 0.006 lbm/MMscf at 38oF and 1000 psig; such anamount is negligible. Ng and Chen (1995) measured a negligible concentrationof MEG in the gas phase at conditions similar to those of this problem.
-Calculate Amount of (a) MeOH and (b) MEG Lost to the Condensate(a) MeOH lost to the condensate. The distribution of MeOH in the condensateis calculated via equation (4)
KLMeOH = exp (5.90 - 5404.5×(1/497.7oR)) = 0.00702 (4)
where oR = oF + 459.69.The mole fraction MeOH in condensate is xMeOH in HC = KL
MeOH×xMeOH in H2O or
xMeOH in HC = 0.00702 × 0.137 = 0.0009617
The condensate rate is 26.0 lbmoles/MMscf (= 25bbl/d×300 lbm/bbl×1lbmol/90 lbm×1d/3.2 MMscf) so that the amount of MeOH in condensate is0.025 lbmol/MMscf (= 0.0009617 × 26 / ( 1 - 0.009617)) or 0.8 lbm/MMscf)
(b) MEG Lost to Condensate. The mole fraction MEG in the water phase iscalculated as
mole fraction MEG = 313.1 lb MEG lb lbmol MEG)
313.1/ 62 + 618.4lb H O / (18lb / lbmolH O)m m
m 2 m 2
/ ( /62
The mole fraction MEG in the water phase is xMEG in H2O = 0.128.
The distribution of MEG between the aqueous liquid and condensate is givenby
KLMEG = exp (4.20 - 7266.4×(1/497.7 oR)) = 3.04 × 10-5 (5)
The mole fraction MEG in condensate is xMEG in HC = KLMEG×xMEG in H2O
calculated as 3.8 × 10-6.(= 3.04 × 10-5 × 0.128). The condensate rate is 26.0lbmoles/MMscf (= 25bbl/d×300 lbm/bbl×1 lbmol/90 lbm×1d/3.2 MMscf) sothat the amount of MEG in condensate is 9.9×10-5 lbmol/MMscf (= 0.0000038× 26 / ( 1 - 0.0000038)) or 0.0061 lbm/MMscf)
-Calculate the Total Amount of MeOH/MMscf and MEG/MMscf
30
MeOH MEG
In Water, lbm/MMscf 174.4 313.1In Gas, lbm/MMscf 34.2 0.006In Condensate, lbm/MMscf 0.8 0.0061Total, lbm/MMscf 209.4 313.11Total, gal/MMscf 31.5 33.3
The example illustrates that for this gas condition, the injection amounts ofMeOH and MEG are comparable. The more precise calculation shown here however,represents a considerable savings in the amount of MeOH injected (31.5 gal/MMscfversus 42.2 gal/MMscf in the second estimation method.)_____________________________________________________________________
II.E. Case Study 6: Prevention of Hydrates in Dog Lake Field Pipeline
As a summary of the thermodynamic hydrate prevention methods, consider thesteps taken to prohibit hydrates in the Dog Lake Field export pipeline in Louisiana, byTodd et al., (1996) of Texaco. During the winter months hydrates formed in the line.While this pipeline passes through shallow water (a marsh) many of the principlesillustrate applications to offshore pipeline design.
Hydrate formation conditions, shown in Figure 16, are calculated via an earlierversion of HYDOFF with 0 wt%, 10%, and 20% methanol in the water phase. TheDog Lake gas composition is: 92.1 mole% methane, 3.68% ethane, 1.732% propane,0.452% i-butane, 0.452% n-butane, 0.177% i-pentane, 0.114% n-pentane, 0.112%hexane, 0.051% heptane, 0.029% octane, 0.517% nitrogen, 0.574% carbon dioxide.
The pipeline pressure and temperature, calculated using PIPEPHASE, weresuperimposed on the hydrate formation curve shown in Figure 17. Gas leaves thewellhead at 1000 psia and 85oF, far from hydrate forming conditions. As the gasmoves down the pipeline, it begins to cool towards ambient temperatures. Once thetemperature reaches approximately 63oF hydrates will form, so methanol must beadded. The figure shows pipeline conditions and the hydrate formation curves forvarious concentrations of methanol, indicating that 25% wt% methanol in water isneeded to inhibit hydrates.
Despite large quantities of methanol injection for hydrate prevention, 110hydrate incidents occurred in the line during winter of 1995-1996 at a cost of$323,732. Combinations of four alternative hydrate prevention methods wereconsidered: (1) burying the pipeline, (2) heating the gas at the wellhead, (3) insulatingthe pipeline, and (4) methanol addition. The details of each prevention measure areconsidered below.
Figure 16 - Dog Lake Field - Hydrate Curves(From Todd, 1997)
0
500
1000
1500
2000
2500
3000
3500
4000
30 35 40 45 50 55 60 65 70Temperature(oF)
Pre
ssu
re(p
sia)
Hydrate Formation Region
Hydrate Free Region
20 wt% MeOH 10 wt% MeOH
0 wt% MeOH
Figure 17 - Dog Lake Field - Original Conditions(From Todd, 1997)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
30 40 50 60 70 80 90Temperature(oF)
Pre
ssu
re(p
sia)
SeparatorWellhead
25 wt%MeOH
20 wt%MeOH
10 wt%MeOH
0 wt%MeOH
Pipeline
31
1. Burying the Pipeline. Some of the Dog Lake pipeline was built over astretch of marsh. The exposure to winter ambient temperatures caused rapidreductions in the gas temperature. Burying the pipeline would protect it from lowenvironmental temperatures due to the higher earth temperatures. Figure 18 displaysthe temperature increase in the pipeline after exposed areas were buried relative to theexposed pipeline in Figure 17. With pipeline burial, the need for methanol in the waterphase was reduced from 26 wt% to less than 19 wt%.
2. Wellhead Heat Addition. Catalytic in-line heaters could be installed at thewellhead to increase the gas temperature to 125oF. Figure 19 shows the pipelinetemperature increase caused by the combined prevention methods of burial andwellhead heating. Use of these two methods permitted the methanol concentration tobe reduced to approximately 14 wt% to prevent hydrate formation in the line. Itshould be noted that heating may increase the amount of corrosion in the line.
3. Insulation. Insulation of exposed areas near the wellhead and battery wouldmaintain higher pipeline temperatures, thereby reducing the amount of methanolneeded for hydrate inhibition. Figure 20 displays the temperature increase in theburied and heated pipeline when exposed pipes were insulated. The pipeline is nowoutside the hydrate formation region, and methanol addition is no longer needed.
4. Methanol Addition. Continued methanol injection could be done at an costof approximately $1.50 -$2.00 per gallon. The cost of methanol to an offshoreplatform cost $2.00 per gallon during the 1996-7 winter. Since methanol recoverymay not be economical, methanol is normally considered an operating cost.
This case study illustrates how combinations of pipeline burial, insulation,heating, and methanol injection can be used to prevent hydrates. The selection of thehydrate prevention scheme(s) is then a matter of economics, as considered in SectionIV of this handbook._____________________________________________________________________
II.F. Hydrate Limits to Expansion through Valves or Restrictions.
When water wet gas expands rapidly through a valve, orifice or otherrestriction, hydrates form due to rapid gas cooling through Joule-Thomson expansion.Hydrate formation with rapid expansion from a wet line commonly occurs in fuel gasor instrument gas lines, as indicated in the platform Example 12 in Section II.F.3.Hydrate formation with high pressure drops can occur in well testing, start-up, and gaslift operations, even when the initial temperature is high, if the pressure drop is verylarge. This section provides methods to determine when hydrates will form upon rapidexpansion. A rough estimation method (Section II.F.1) is followed by a more accurate
Figure 18 - Dog Lake Field with Burial(From Todd, 1997)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
30 40 50 60 70 80 90
Temperature(oF)
Pre
ssu
re(p
sia)
Separator Wellhead
20 wt%MeOH
10 wt%MeOH
0 wt%MeOH
Pipeline
Figure 19 - Dog Lake Field with Burial and Heating(From Todd, 1997)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
30 40 50 60 70 80 90 100 110 120 130
Temperature(oF)
Pre
ssu
re(p
sia)
WellheadSep.
20 wt%MeOH
10 wt%MeOH
0 wt%MeOH
Pipeline
Figure 20 - Dog Lake Field with Burial, Heating, and Insulation
(From Todd, 1997)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
30 40 50 60 70 80 90 100 110 120 130Temperature(oF)
Pre
ssu
re(p
sia)
WellheadSeparator
20 wt%MeOH
10 wt%MeOH
0 wt%MeOH
Pipeline
32
but resource intensive method (Section II.F.2), concluding with prevention techniquesin Section II.F.3.
Figure 7 is a schematic of the pressure and temperature of a pipelineproduction stream during normal flow with entry into the hydrate formation region. Ifthe gas expands rapidly, the normal pipeline cooling curve of Figure 7 will take on amuch steeper slope, but the hydrate formation line remains the same. Two rapidexpansion curves for a 0.6 gravity gas are shown in Figure 21. Intersections of the gasexpansion curves with the hydrate formation line gives the limiting expansiondischarge pressures from two different high initial pressure/temperature conditions.
In Figure 21, the curves specify the pressure at which hydrate blockages willform at the restriction discharge for an upstream pressure and temperature. Gas Aexpands from 2000 psia and 110oF until it strikes the hydrate formation curve at 780psia (and 57oF) so that 780 psia represents the limit to hydrate-free expansion. Gas Bexpands from 1800 psia (120oF) to intersect the hydrate formation curve at a limitingpressure of 290 psia (42oF). In expansion processes while the upstream temperatureand pressure are known, the discharge temperature is almost never known, but thedischarge pressure is normally set by a downstream vessel or pressure drop.
Cooling curves such as the two in Figure 21 were determined for constantenthalpy (or Joule-Thomson) expansions, obtained from the First Law ofThermodynamics for a system flowing at steady-state, neglecting kinetic and potentialenergy changes:
∆H = Q - Ws (6)
where ∆H is the enthalpy difference across the restriction (downstream - upstream),while Q represents the heat added, and Ws is shaft work obtained at the restriction.Offshore restrictions have no shaft work, and because the system operatesadiabatically, both Ws and Q are zero, resulting in constant enthalpy (∆H =0) operationon expansion.
Due to the constant enthalpy requirement, rapid gas expansion results incooling, except at very high pressures, where heating occurs on expansion due to acompressibility decrease with temperature. The upstream pressure at which thesystem changes from heating to cooling upon expansion is called the Joule-Thomsoninversion pressure.
Rule-of-Thumb 7. Natural gases cool upon expansion from pressures below 6000psia; above 6000 psia the temperature will increase upon expansion. Virtuallyall offshore gas processes cool upon expansion, since only a few reservoirs and nocurrent pipelines or process conditions are above 6000 psia.
Figure 21 - Gas Expmsion into Hydrate Forrmtioo Region
(From Katz, 1944)
2000
1500
1000
800 d .- :: ;I L 600 Z E 500 k
400
300
30 40 50 60 70 80 90 100 1
Temperature(F)
33
Rule-of-Thumb 7 was determined by G.G. Brown at the University o Michigan(1945) who constructed the first natural gas enthalpy - entropy charts.
II.F.1. Rapid Calculation of Hydrate-Free Expansion Limits. Katz (1945)generated charts to determine the hydrate-free limit to gas expansion, by the gasgravity chart (Figure 9) to obtain the hydrate formation line in Figure 21, with gasenthalpy-entropy charts by Brown (1945) to obtain the cooling line.
Cautioning that the charts applied to gases of limited compositions, Katzprovided expansion charts for gases of 0.6, 0.7, and 0.8 gravities, shown in Figures 22,23, and 24 respectively. The abscissa (or x axis) in each figure represents the lowestdownstream pressure without hydrate formation, given the upstream pressure on theordinate (y axis) and the upstream temperature (a parameter on each line).
It should be noted that the maxima in Figures 22, 23, and 24 occur at an inletpressure of 6000 psia, the Joule-Thomson inversion pressure. This provides a furthervalidation of Rule-of-Thumb 7 above.
The following three examples for chart use are from Katz’ original work._____________________________________________________________________Example 10a Maximum Pressure of Gas Expansion. To what pressure may a 0.6gravity gas at 2000 psia and 100oF be expanded without danger of hydrate formation?
Solution: From Figure 22, read 1050 psia.
Example 10b. Unlimited Gas Expansion. How far may a 0.6 gravity gas at 2000 psigand 140oF be expanded without hydrate formation?
Solution: In Figure 22 it is seen that there is no intersection with the 140oF isotherm.Hydrates will not form upon expansion to atmospheric pressure..
Example 10c. Minimum Initial Temperature Before Expansion. A 0.6 gravity gas is tobe expanded from 1500 psia to 500 psia. What is the minimum initial temperature thatwill permit the expansion without danger of hydrates?
Solution: From Figure 22 the answer is read as 99oF or above._____________________________________________________________________
Figures 22, 23, and 24 for gas expansion incorporate the inaccuracies of gasgravity charts from which they were derived. As indicated in Section II.C the 0.6gravity chart (used for both hydrate formation and gas expansion) may haveinaccuracies of ± 500 psia. Accuracy limits to these expansion curves have been tested
10000 -
8
6
4
2
1000
6
6
4
2
100
-I
! i
_
_
_
_
_
_
_
_
Figure 22 - ffas Emansion of 0.6 6as Gravitv W6 (From Katz.1959)
Initial 1
_ _ -
2 4 6 6 1000
Pressure (psia)
100 2
10000 6
6
Fimure 23 - Gas Exsansion of 0.7 ffas Gram NG (From Katz,1959)
~ _I_ _ _ I
-I- r - - -/- - - T
I I I I I
I I I I I
2 _ 1 _ ‘_ L ~ _ _’ _ _ _ ! I I I I I
I I I I I I
l I I _ _ _ ~
I I I
- f -I- I
I I I
~ i -I- I
I I I
I I I
I I I
I I I
I I I
I I I
_ 1 _I_ I
I I I
I I I
~ 7 -I- I
I I I
- i -I- I
I I I
I I I
I I I ~ - _ _
I I I
I I I
I I /
I I I II/I
I I I 2 4 6 6 2 4 6
100 1000 610000
F,inal Pwssuya fpsia\
(From Katz, 1959) 10()OOT - - -~ - -
2
100
_ _,_ _,_ + -
I I I
I I I
I I I _ - _ _ _ - -
I I I
I I I
I I I
I I I I I I I
2 4 6 a 1000
Final Pressure (psia)
--- -- r I
-+--
l - - - - -
I
I
I
I I
2
34
by Loh et al. (1983) who found for example, that the allowable 0.6 gravity gasexpansion from 150oF and 3500 psia should be 410 psia rather than the value of700psia, given by Figure 22.
II.F.2. More Accurate Calculation of Hydrate-Free Limits to Gas Expansion.A more accurate computer method is available, using the same principles indicated inFigure 21. Just as before, for an initial temperature, pressure and gas composition, theintersection of an isenthalpic (∆H=0) cooling curve with the hydrate three-phase locusmay be determined. In the new method, the isenthalpic line is determined via amodern equation-of-state, and the program HYDOFF replaces the gas gravity chart topredict hydrate formation conditions. While this method requires more resources(namely time and an IBM-compatible computer) than the Joule-Thomson charts, itresults in higher accuracy and provides an estimation of the amount of methanolinhibitor required.
In order to use the more accurate method, the first step is to generate thehydrate stability pressure-temperature line as in Figure 21, using HYDOFF asindicated in Section II.D.1. Later the amount of methanol injected to displace thehydrate formation curve to the left can be calculated, as illustrated in Example 12 inSection II.F.3 at the close of this Section.
The computer program XPAND is included with this handbook for calculationof the second, Joule-Thomson expansion line, which intersects the hydrate formationline. The expansion line is calculated with an equation-of-state, using the methoddetailed by Sloan (1998, Appendix A). Given an inlet temperature, pressure, and gascomposition, the program calculates the enthalpy change (∆H) for a specified outletpressure and a temperature guess. The user changes the outlet temperature guess untila value of ∆H = 0 is obtained. The resulting discharge temperature and pressure isplotted to obtain the expansion curve. For one inlet temperature and pressure, a seriesof such discharge points provides a curve which intersects the hydrate formation curveat the limiting temperature and pressure of expansion. The result may be comparedwith the Joule-Thomson result in Figures 22, 23, and 24.
_____________________________________________________________________Example 11: Hydrate Formation on Expansion of a Natural Gas
A simple natural gas consists of 90 mol% CH4 , 7% C2H6 , and 3% C3H8 withfree water in a pipeline. Two initial inlet process conditions are considered forexpansion across a valve: (a) 68oF and 2180 psia, or (b) 77oF and 2180 psia. Foreither condition, is hydrate formation a possibility? Are there process limitations onthe expansion from either initial condition to 1450 psia?
35
Solution: Before doing any hydrate calculations, one should confirm that this gas isnot close to the hydrocarbon dew point, to eliminate the possibility of encounteringboth vapor and liquid hydrocarbon phases. The expansion program was written for agas phase. A vapor-liquid equilibria flash calculation indicates that the highesttemperature at which a hydrocarbon liquid can occur (the cricondentherm) for thismixture is -44oF, so the process will not form hydrocarbon liquid.
Figure 25 shows the expansion conditions of both inlet conditions for the gas.The remainder of this example concerns the generation of Figure 25 and theprocessing implications. First, the pressures and temperatures of hydrate formationare calculated using the program HYDOFF as in Section II.D as:
T(oF) 32 35 40 45 50 55 60 65 68 71 77P(psia) 119 149 213 303 368 551 718 1117 1624 2509 4046
A semi-logarithmic interpolation of the above values gives the hydrateformation point at 70oF when the pressure is 2180 psia. Therefore the initial conditionof 68oF and 2180 psia is within the hydrate formation region, but the initial conditionsof 77oF and 2180 psia remains in the fluid (vapor-liquid water) region.
If the system at 68oF and 2180 psia has formed hydrates, consider two meansof depressurization. If the system pressure is lowered to 1450 psia slowly andisothermally (with substantial heat input) hydrates will dissociate at 1537 psia. Asecond, isenthalpic (∆H=0) depressurization without heating from the surroundings,results in much colder gas at 1450 psia. Using XPAND on the disk accompanying thishandbook (see the User’s Manual prescription in Appendix B) the followingisenthalpic line is obtained:
P (psia) 2100 2000 1800 1600 1450T (oF) for ∆H=0 68.0 62.4 55.2 46.9 39.8
As shown in Figure 25, the isenthalpic expansion system extends further intothe hydrate region. Only with subsequent heating at a constant pressure of 1450 psia,will the system become hydrate-free at 66.6oF.
A similar calculation for the system initially in the fluid region at 77oF and 2180psia shows the problem with isenthalpic expansion. The result, plotted as line ABC inFigure 25 shows an isenthalpic intersection with the hydrate formation boundary atapproximately 70.5oF, 1990 psia. To prevent expansion into the hydrate region fouroptions may be considered, as illustrated in Example 12:
1. limit the final expansion pressure to a higher value than 1990 psia,2. add inhibitor at the restriction inlet,3. dehydrate the gas before expansion, or
Figure - 25 Joule-Thomson Cooling Through Gas Expansion(From Sloan, 1998)
0
500
1000
1500
2000
2500
3000
30 35 40 45 50 55 60 65 70 75 80Temperature(oF)
Pre
ssu
re(p
sia)
Hydrate Formation Curve
∆H = 0 ∆H = 0
Isenthalpic ExpansionFrom 68oF, 2180 psia
Isenthalpic ExpansionFrom 77oF, 2180 psia
Isothermic ExpansionFrom 68oF, 2180 psia ∆T = 0
C
BA
36
4. heat the gas to a higher inlet temperature.
Pipeline hydrate plugs are frequently porous, so that depressurization from one(downstream) side can result in Joule-Thomson cooling as gas flows through the plug.Expansion across a hydrate plug yields identical results to expansion across a valve. Inthe initial part of the above example, it was seen that expansion from a conditionwhich has a hydrate plug (e.g. 68oF and 2180 psia) will only cause the downstreamportion of the plug to progress further into the hydrate region. Heat must be put intothe system from the surroundings to dissociate hydrates. The field tests which confirmthe above discussion are given in Case Studies C.15 and C.17 in Appendix C.
There are several limitations to XPAND. First, it is limited to the vapor phaseand will not account for expansion of a fluid containing any liquid amount. If there isa question whether the system might contain a liquid either at the inlet or discharge,the engineer should calculate the hydrocarbon dew point, and an isenthalpic flashshould be performed to obtain the cooling curve, using a process simulator packagelike HYSIM�, ASPEN�, or PROCESS�. Secondly, XPAND was generated only for thefirst five common paraffins (methane, ethane, propane, normal butane, iso-butane, andnormal pentane) so XPAND cannot be used with nitrogen, acid gases (H2S or CO2),or with significant amount of heavy components. With the above restrictions, theengineer may group components larger than pentanes into the “pentane plus” fractionof the gas.
II.F.3. Methods to Prevent Hydrate Formation on Expansion. Frequently gasexpansion causes hydrate formation in fuel gas lines and in instrument gas lines on aplatform, which may result in other, larger hydrate problems. In some cases, hydrateformation in a platform instrument gas line has caused system shutdown; subsequentcooling of the non-flowing pipeline into the hydrate formation region resulted in apipeline blockage upon resumption of flow.
The following example provides a Section II.F summary of hydrate preventionduring gas expansion, with four methods for hydrate prevention in a fuel gas line,which is used to supply power to platform compressors.
_____________________________________________________________________Example 12: Hydrate During Gas Expansion
An offshore platform design required fuel gas at 300 psia and a rate of 0.02MMscf/d from a high pressure flowline at 1500 psia and 100oF. The inlet flowline wasoffgas from the first stage separator (see Figure 8, Example 3) so the gas wassaturated with water. A control valve was placed on fuel gas line from the inletflowline to provide the required pressure and flow of fuel gas. The mole fraction
37
composition of the components were: 0.927 methane, 0.053 ethane, 0.014 propane,0.0018 i-butane, 0.0034 n-butane, and 0.0014 i-pentane.
Is there a chance that hydrate formation might occur in the fuel gas line? If so,which of the following ways could be used to prevent hydrates?
1. two stage expansion with intermediate heat addition,2. methanol injection upstream of expansion,3. parallel expansions, and4. drying the inlet gas.
Solution: The example solution is provided with the following steps:
Ex12.A1. Hydrate-Free Expansion Limits Using the Joule-Thomson DiagramsEx12.A2. Hydrate-Free Expansion Limits Using HYDOFF and XPANDEx12.B1. Prevention via Heat Addition to Two-Stage ExpansionEx12.B2. Prevention via Methanol Injection Upstream of ExpansionEx12.B3. Parallel ExpansionsEx12.B4. Drying the Inlet Gas
Ex12.A1. Hydrate Prediction Through Joule-Thomson Diagrams. Using theKatz Joule - Thomson expansion diagrams (Figures 22, 23 and 24), the minimuminitial temperature required for hydrate-free operation can be estimated. This gas isidentical with that in Example 4, whose gravity is calculated as 0.603. Figure 22provides an estimate that a 0.6 gravity natural gas must have an initial temperature of104oF to prevent hydrate formation during gas expansion from 1500 psia to 300 psia.Under the current design the initial temperature of 100oF will cause hydrates to formjust downstream of the fuel gas control valve.
Ex12.A2. Hydrate Prediction Using XPAND and HYDOFF. XPAND wasused to calculate the discharge temperature of the natural gas upon expansion, usinginputs of the upstream valve pressure, temperature and gas composition to calculatethe downstream gas temperature at a given discharge pressure. Appendix B gives astep-by-step XPAND User’s Manual for the calculation in this example.
Once the expansion P-T values are obtained, they are plotted to determine theintersection with hydrate formation curves (including inhibited curves) generated byHYDOFF, as done in Section II.D. Figure 25 shows such intersections.
In Figure 26 note that the expansion line is curved, requiring calculation ofseveral temperatures and pressures along the expansion line. The expansion enters theuninhibited formation region at 53oF and final temperature after expansion is calculatedto be 33oF. For a comparison with 105oF inlet temperature requirement by the Katz
Figure 26 - Hydrate Formation Curve for Single Valve Expansion
0
200
400
600
800
1000
1200
1400
1600
30 40 50 60 70 80 90 100 110Temperature(oF)
Pre
ssu
re(p
sia)
Inlet
Outlet
HydrateFormation
Curves
Gas Expansion Curve
Hydrates
No Hydrates
20 Wt% MeOH 10 Wt% MeOH0 Wt% MeOH
38
Joule-Thomson charts, the inlet temperature using XPAND should be 108oF forhydrate-free expansion from 1500 psia to 300 psia.
Ex12.B. Hydrate Prevention
After establishing that hydrates will form upon gas expansion, the platformdesign had to be modified to inhibit hydrate formation. Four hydrate preventionmethods were considered: 1) Heat addition to two stage expansion, 2) methanoladdition, 3) parallel expansion, and 4) drying the gas. Details of each preventionmethod are provided below.
Ex12.B.1. Heat Addition with Two-Stage Expansion. In-line heaters could beinstalled to raise the temperature of the gas outside the hydrate formation region. Inthe case considered here, two control valves are used with an in-line heater betweenthem. Figure 27 is a schematic of the two control valves and in-line heater design forthe fuel gas line. The cooler gas present after the first pressure drop facilitates heattransfer before the second valve. The following calculations provide the pressure andtemperature conditions in the system shown in Figure 24.
In our example, the pressure ratio (Pin/Pout) will be arbitrarily set at a valueapproximately equal across each control valve, providing 675 psia as the intermediatepressures after the first control valve. Using XPAND the temperature of the gas at675 psia is predicted to be 58oF at the first valve discharge. Figure 28 shows the gasexpansion conditions and the HYDOFF hydrate formation curves, demonstrating thatthe gas is outside the hydrate formation region after the first pressure drop (line 1).
In Figure 28, heat is added to the system (line 2) to raise the temperature toprevent hydrates upon gas expansion across the second control valve (line 3). Theheat duty in the exchanger was defined by the temperature increase (T3-T2). XPANDwas used to estimate a value of T3 at the second valve inlet which provided a dischargevalue T4 outside the hydrate formation region. For this example, a T3 of 68oF isrequired to maintain the final temperature at 44oF, just above the hydrate formationregion at the required pressure of 300 psia.
Figure 28 suggests that heating before expansion through a single control valvemay provide a more economical method to prevent hydrates on expansion. A singlecontrol valve and heater would save the capital cost of one control valve and may be abetter alternative to prevent hydrates on expansion.
Ex12.B.2. Methanol Addition. Methanol can be injected into the fuel supplyline upstream of the control valve to prevent hydrate formation downstream of thevalve. Figure 26 shows that more than 10 wt% methanol is needed in the free waterphase to prevent hydrate formation. A better estimate of 12 wt% methanol in the
P1 = 1500 psia
T1= 100oF
P2= 675 psia
T2= 58oF
P3= 670 psia
T3= 68oF T4= 44oF
P4= 300psia
1st Control Valve 2nd Control ValveIn-Line Heater
Estimated UsingHYDXPAND
Figure 27 - Two Stage Gas Expansion with Heating
Figure 28 - Two Stage Gas Expansion with Heat Addition
0
200
400
600
800
1000
1200
1400
1600
30 40 50 60 70 80 90 100 110Temperature(oF)
Pre
ssu
re(p
sia)
Inlet1st Valve(T1)
Outlet2nd Valve(T4)
Line #1
Heating - Line #2
Line #3
Inlet2nd Valve(T3)
Outlet1st Valve(T2)
20 Wt% MeOH10 Wt% MeOH0 Wt% MeOH
Hydrates
No Hydrates
Gas ExpansionCurve
39
water phase was obtained through interpolation using XPAND and HYDOFF. Thetotal amount of methanol required for upstream gas injection is calculated throughmethods of Section II.D.
Ex12.B.2.a.Water condensation with expansion. Gas flows into the fuel line ata rate of 0.02 MMscf/d. Since the gas is saturated with water, one cancalculate the mass of free water in the pipeline due to dewpoint condensationfrom Figure 10 (45 lbm H2O/MMscf in the vapor at 1500 psia and 100oF and 16lbm H2O/MMscf in the vapor at 350 psia and 33oF). The amount of free waterthat forms from the vapor is
45 lbm/MMscf- 16 lbm/MMscf = 29 lbm/MMscf.
Consequently, the total amount of water (W) condensed per day is:
29 0 02 0582 2lb H O
MMscf
MMscf
day
lb H O
daym m× =. .
Ex12.B.2.b. Mass of MeOH Required in the Water Phase. The mass ofMeOH can be found by using the definition of weight percent
wtM lb MeOH
M lb MeOH W lb H OXm
m m
%( )
( ) ( )=
+ 2
100%
Solving for 12 wt%, the amount of methanol, M = 0.079 lbm MeOH/day
Ex12.B.2.c. Mass of MeOH Lost to Condensate and Vapor. The mole fractionof MeOH in the water is found by the equation:
mole fraction MeOH = 0.079 lb MeOH lb lbmol MeOH)
0.079 / 32 + 0.58 lb H O / (18lb / lbmolH O)m m
m 2 m 2
/ ( /32
The mole fraction MeOH in the water phase is xMeOH in H2O = 0.071. Thedistribution coefficient of MeOH in the gas is calculated at 33.03oF (492.7oR)by Equation (3), relative to the methanol in the water
KvMeOH = exp (5.706 - 5738×(1/492.7oR) = 0.00263 (3)
The mole fraction of MeOH in the vapor is yMeOH = KvMeOH•xMeOH in H2O or
yMeOH = 0.00263 × 0.071 = 0.000187
40
The daily gas rate is 52.7 lbmol (= 2.0 × 104 scf / (379.5 scf/lbmol)), so thatthe MeOH lost to the gas is 0.0098 lbmol (= 0.000187 × 52.7) or 0.314lbm/day.
No condensate is formed in the pipeline, consequently there is no MeOH lostto the liquid hydrocarbon phase.
Ex12.B.2.d. Total Mass of MeOH Needed. The total amount of MeOHinjected is the sum that in the vapor (0.314 lbm) condensate (0), and water(0.079 lbm) = 0.393 lbm MeOH/day (0.06 gal/day) injection required to inhibitthe fuel gas line, with injection before the control valve as shown in Figure 29.
Ex12.B.3. Parallel Gas Expansion. Operating personnel sometimes suggestthat fuel gas lines be placed in parallel to provide more than one gas expansion asshown in Figure 30. If one control valve becomes plugged with hydrates and shutdown, the second gas line is then opened while the first line is depressurized forhydrate dissociation. In this manner, it is hoped that flow can be maintained in onefuel gas line without the need for hydrate inhibition.
Conditions of hydrate formation on parallel gas expansion are exactly the sameas shown in Figure 26. The capital cost is doubled however, and there is the risk thatthe parallel valve may become hydrated before the plug is removed from the initial line.This solution technique addresses the effect of hydrate formation rather than its cause,and should be considered less than optimal operating practice.
Ex12.B.4. Drying the Inlet Gas. If the gas inlet is dry, hydrate formationcannot form due to insufficient water. It is good design practice to place both fuel gasand instrument gas lines downstream of a TEG drying unit or a molecular sieveadsorption tower. The design of a drying unit is outside of the scope of thishandbook, but it is readily available in standard texts on gas processing (e.g. Manningand Thompson, 1991)._____________________________________________________________________
Of the above four design methods to prevent hydrates in fuel gas lines, themost satisfactory from the standpoint of expense and operating practice is to providedry inlet gas with a fuel gas line downstream of the TEG dryer. As Deaton and Frost(1946, p. 41) stated in their classic study of hydrate formation and prevention:
“The only method found to be completely satisfactory inpreventing the formation of hydrates in gas transmission lines is todehydrate the gas entering the line to a dew point low enough topreclude formation of hydrates at any point in the system.”
P2=300 psiaP1=1500 psia
T1=100oF T2=33oF
0.393 lbm MEOH/day
Control Valve
.
Figure 29 - Single Valve Gas Expansion with Methanol Injection
Gas Inlet of0.02 MMSCF
per day
P1=1500 psia P2=300 psiaT1=100oF
T2=33oF
P1=1500 psia
P2=300 psia
T1=100oFT2=33oF
Flowline #1
Flowline #2
High Pressure Flowline
Figure 30 - Parallel Gas Expansion
41
The study of gas expansion without hydrate formation suggests twoadditional Rules-of-Thumb, stated below.
Rule-of-Thumb 8. It is always better to expand a dry gas than a wet gas,in order to prevent hydrate formation in unusual circumstances, e.g.changes in upstream pressure due to throughput changes.
Rule-of-Thumb 8 is illustrated by the previous example, which typifiesinstrument or fuel gas applications. To use this Rule-of-Thumb it is necessaryto be able to dry the gas, using either a glycol dehydrator or a molecular sieveadsorption process.
Rule-of-Thumb 9. Where drying is not a possibility, it is always better totake a large pressure drop at a process condition where the inlettemperature is high.
One application of Rule-of-Thumb 9 is the bottom hole choke,provided in Texaco’s Reliability Engineering: Gas Freezing & Hydrate Study, ahandbook for field personnel by Todd et al. (1996). A bottom hole choke is adevice with a restricted opening, placed in the lower end of the tubing string tocause a large pressure drop to be taken deep in the wellbore. The warmdownhole reservoir heats the gas before it expands, thus preventing hydratesfrom forming across the expansion. The majority of bottom hole chokes areinstalled in high pressure gas wells that producer a low amount of liquids.
II.G. Hydrate Control Through Chemical Inhibition and Heat Management
There are four classical approaches to hydrate inhibition, discussed at thebeginning of Section II:
1. remove water from the system,2. increase the temperature,3. decrease the pressure, or4. insert a component to attract water molecules, such as an alcohol or glycol.
Two additional, new inhibition techniques have been commercialized and aregaining industrial acceptance:
5. the kinetic inhibition method of preventing sizable crystal growth for a periodexceeding the free water residence time in a pipeline, and
6. the anti-agglomerant method which uses a surfactant to stabilize thewater/hydrate phase as small emulsified droplets within a liquid hydrocarbon.
Thermodynamic inhibition (methods 1 through 4) prohibit hydrate formationaltogether, while with the newer methods (5 and 6) the system is allowed to existwithin the hydrate stability zone, so that small crystals are stabilized for some time
42
period without growing to larger masses. While thermodynamic inhibitors are thestandard practice offshore, there are successful commercial instances of kineticcontrol. The incentive for newer kinetic control methods is a substantial capital costreduction by the elimination of the need for offshore platform equipment, a smalloperating cost reduction, and elimination of some environmental concerns. In thefuture innovative methods of heat management through heating and insulation mayprovide thermodynamic protection against hydrates.
Section II.G.1 discusses design and operation with thermodynamic inhibitionchemicals (methanol and monoethylene glycol). Section II.G.2 discusses design andoperation with kinetic inhibitors. Section II.G.3 summarizes the chemical inhibitor useguidelines. Section II.G.4 shows the methods of heat management to retain a highinlet temperature in the fluid region.
II.G.1 Inhibition with Methanol or Monoethylene Glycol
II.G.1.a Methanol. Of all hydrate inhibitors, methanol is the most widely used.Methanol is also the best and most cost effective of the alcohols. Hydrate inhibitionabilities are less for larger alcohols (i.e. methanol > ethanol > isopropanol.) Typicallymethanol is vaporized into the gas stream of a pipeline, then dissolves in any free wateraccumulation(s) to prevent hydrate formation.
For methanol injection into wells, a commercial program such as WELLTEMP�
can be used to predict the flowing temperature and pressure (in an identical manner tothat used with PIPEPHASE� or OLGA� in Example 2 of Section II.A). The downholemethanol injection point is placed at the well depth for which the well temperature andpressure are predicted to cross into the hydrate formation region, for both wellproduction and well testing conditions. Usually the flowing well conditions are warmenough to prevent hydrate formation.
The methanol amount needed in free water of either wells or flowlines may bedetermined using Hammerschmidt’s equation or HYDOFF, as illustrated in SectionsII.C. and II.D. Typically the free water concentration of methanol in onshore pipelinesis about 20 wt%, while offshore methanol concentrations can exceed 50 wt% if thepressure is high.
A recent finding is that under-inhibition with MeOH is worse than no inhibitionfor two reasons, as measured by Yousif et al, (1996): (1) under-inhibited systems formhydrates faster than systems without inhibitors, and (2) hydrates stick to the pipe wallsmore aggressively when insufficient methanol is injected.
While hydrate inhibition occurs in the water phase, significant amounts ofmethanol are also dissolved in the vapor and oil/condensate phases. Proportions ofmethanol dissolved in the vapor or oil/condensate phases are calculated via the
43
methods of Sections II.C and II.D, and are usually taken as operating expense losses.Methanol loss costs can be substantial when the total fraction of either the vapor orthe oil/condensate phase is very large relative to the water phase. Sample economicsfor methanol are provided in Section IV and in the following Case Study 7.
Makogon (1981, p. 133) noted that in 1972 the Soviet gas industry used 0.3kg of methanol for every 1000 cubic meters of gas extracted. Norsk Hydro workers(Stange et al. 1989) indicated that North Sea methanol usage may surpass the ratiogiven by Makogon by an order of magnitude. The use of methanol in the North Seahas become so expensive that alternatives to methanol injection are considered.
_____________________________________________________________________Case Study 7. Methanol Recovery from the Water Phase
Paragon Engineering (1994) performed a study for DeepStar (DSII CTR 221-1) of the impact of methanol recovery on offshore systems. As an evaluation scenario,a conventional, shallow water platform was designed solely for methanol recovery in100-150 feet of water, with methanol return lines 40-60 miles to deepwater subseawells. Figure 31 shows a block flow diagram for methanol recovery and injection.
Costs were determined for methanol recovery on the platform for eight casesof methanol in the produced water. Table 3 shows results for four cases: 20wt% and30wt% methanol in the free water phase, for (a) high water production in late field life,and (b) low water production in early field life.
Table 3. Methanol 1994 Costs with Offshore Platform RecoveryCase High Water (Late Life) Low Water (Early Life)Amount of MeOH in H2O, wt% 30 20 30 20
Oil Production, bpd 13,188 13,191 48,813 48,802Produced Water, bpd 14,593 14,498 3,196 3,188Gas, MMscf/d 15 15 57 57Injected MeOH, bpd 7,797 4,537 1,668 960MeOH Loss to Gas, lbm/d 6,412 4,430 23,443 15,977MeOH Loss to Gas, % 0.29 0.35 4.72 5.53MeOH Loss to Oil, lbm/d 2,176 1,456 7,914 5,224MeOH Loss to Oil, % 0.10 0.11 1.59 1.81
Capital and Operating Cost CalculationsInstalled Cost on Platform, $MM 16.7 13.3 5.03 4.20Total Cost with Platform, $MM 20.8 17.4 9.14 8.31Operating Cost, $MM/yr. 5.78 4.39 4.25 2.99
Deepwater (4000 ft. w.d)Subsea Well &
Template
12” Production Pipeline
4” Methanol Re-injection
Oil/Gas/WaterSeparation
Gas TreatingDehydrationCompression& Metering
Oil TreatingPumpingMetering
Water Treating
MethanolRecoveryFacilities
MethanolStorage
Water
Oil
Shallow Water Platform (150 ft. w.d)
Oil/Gas to SalesPipeline
Water Overboard
50 miles to Platform
Max. MeOH Min. MeOHRec. Facil. Rec. Fac.
Gas Flow (MMSCFD) 15.3 56.4Oil Flow (BPD) 13,200 48,800Water Flow (BPD) 14,600 3,380MeOH Inj. (BPD) 7,800 200MeOH Rec. (%) 99.5 91
Figure 31 - Methanol Recovery and Injection(From Manning and Thompson, 1991)
44
In all cases methanol was recovered as the overhead product from a 40 traydistillation column. The bottoms methanol concentration was less than 1000 ppm sothat water could be dumped overboard.
Paragon Engineering also reported methanol losses which were greater thananticipated in North Sea recovery systems from three Conoco facilities (4-5 gal MeOHlost/MMscf), a Norsk Hydro recovery unit (29% MeOH losses), and an AmocoNetherlands recovery unit (12% MeOH losses)._____________________________________________________________________
Methanol recovery is possible from the vapor phase, using a cryogenicrecovery process, but this is seldom done due to the expense involved. Methanol canbe recovered from the condensate via a water-wash and subsequent distillation, butthis is also seldom done. Environmental concerns have a major impact on recovery.
II.G.1.b Monoethylene Glycol. Of the glycols, mono-ethylene glycol (MEG)dominates pipeline injection over di-ethylene glycol (DEG) and tri-ethylene glycol(TEG) because MEG has a lower viscosity and is more effective per pound. MEGalso has a higher molecular weight and a lower volatility than methanol, so MEG maybe recovered and recycled more easily on platforms. In addition MEG losses to thevapor and oil/condensate phases are very small relative to methanol. Consequently,MEG is most applicable for small water fractions when gas and oil/condensatefractions are very high. The MEG injection amount may be calculated using methodsin Sections II.C and II.D.
Rule-of-Thumb 10. Monoethylene glycol injection is used when the requiredmethanol injection rate exceeds 30 gal/hr.
Rule-of-thumb 10 was obtained from Manning and Thompson (1991, p. 86).
Unlike methanol, MEG’s low vapor pressure requires that it be atomized into apipeline. After injection, MEG is retained with the water phase and provides nohydrate protection above the water level. Due to it’s high viscosity and density, MEGis seldom used to dissociate a hydrate plug unless the injection point is vertically abovea hydrate plug (as in a riser or a well); methanol is normally used for flowline plugs..
Figure 32 shows a MEG recovery unit that appears very similar to themethanol recovery block diagram in Figure 31. However in the methanol column theoverhead may be almost pure methanol, while in the glycol regenerator MEG isrecovered with water (typically at 60-80 wt%) at the bottom. Salt also concentrates inMEG regenerator bottoms (due to low salt vapor pressure) when salt water isproduced in the well stream inhibited by MEG. The salt solubility limit in MEG isfrequently exceeded, resulting in salt precipitation and fouling of column trays,exchangers, and other equipment.
FuelGas
GlycolRegenerator
WaterVapor
Glycol-GlycolHXER
Glycol-OilSeparator
Oil to StabilizerRich
Glycol
Low TempSeparatorChoke
Bypass Valve
HXER
GlycolPump
Lean GlycolFilter
Free WaterKnockout
Glycol Inj.NozzleWellstream
Water
Gas
Residue Gas
Figure 32 - MEG Recovery and Regeneration(From Manning and Thompson, 1991)
45
II.G.1.c Comparison of Methanol and Glycol Injection. In a comprehensive setof experimental studies, Ng et al. (1987) determined that methanol inhibited hydrateformation more than an equivalent mass of glycol in the aqueous liquid.
Methanol usage (principally in flowlines and topside on platforms)predominates in the Norwegian sector of the North Sea; MEG is principally used forhydrates in wells and risers. In contrast, MEG dominates BP’s inhibition use in theNorth Sea. Major problems with use of MEG are high viscosity in long lines and saltprecipitation upon regeneration. Methanol use is much more prevalent than MEG inthe United States.
While there is no robust strategy to discriminate between the use of methanoland MEG, the choice seems to depend upon (a) plug location, (b) fluid effects, and (c)properties of the plug in question. The table below provides a summary.
Table 4. Methanol and Monoethylene Glycol Attributes Comparison
HydrateInhibitor
Methanol (MeOH) Monoethylene Glycol (MEG)
Advantages -easily vaporized into gas -easy to recover-for flowline & topside plugs -for plugs in wells and risers-no salt problems -low gas &condensate solubility
Disadvantages -costly to recover -high viscosity inhibits flow-high gas & condensate losses -salt precipitation and fouling-too little is worse than none -remains in aqueous phase-costly in condensate product(See Table 13 Section IV.B.1.a)
A step-wise list of considerations before injection of methanol andmonoethylene glycol are provided in Table 5 at the end of Section II.G.3.
II.G.2. Kinetic Control by Anti-Agglomerants and Kinetic Inhibitors
The reader is referred to the text by Sloan (1998, Section 3.3) for the theory ofhydrate prevention using the two new techniques of anti-agglomeration and kineticinhibition. At the time of this writing, the kinetic inhibition area is changing rapidlywith substantial research and development, and only a few good examples ofcommercial application exist. With some inhibitors, substantial advantages are claimedfor combinations of anti-agglomerants and kinetic inhibition.
46
II.G.2.a Anti-Agglomerants. Figure 33 shows a schematic of the method foranti-agglomeration. In the upper diagram hydrates form large black masses and cangrow to a size to plug the pipeline. In the lower portion of Figure 33, a surfactantemulsifier has been added to the gas condensate system to cause the water to besuspended as small droplets in the condensate.
With this inhibition mechanism, hydrate droplets form, and both gas and waterare consumed, but hydrates are prevented from agglomerating to larger hydratemasses capable of plugging pipelines. Even though hydrates are formed, theirsuspension may provide acceptable flow properties such as low pressure drops. Anti-agglomerant inhibitors are particularly effective in preventing hydrate pluggage or flowstoppages such as shut-ins, with subsequent cooling and restarting.
As surfactant molecules, anti-agglomerants have one water-attractive end,while the other end attracts oil, causing a lower surface tension between oil and water.With excess oil, a surfactant causes the water phase to be suspended as emulsifieddroplets. However with excess water, the emulsion may be reversed and water will bethe external phase. Surfactant chemistry is complex and a different surfactant may berequired to emulsify water with each oil (or condensate).
Lingelem, et al. (1994) present Norsk-Hydro data in Figure 34 as an exampleof anti-agglomerant behavior in a multiphase pipeline that did not exhibit pluggingwhen the initial water-to-oil ratio (WOR) was below 60% (volume), even with hydrateformation. In contrast, plugging was observed above 60% WOR with less than 10wt% methanol in the free water. Other multiphase oil pipelines (not shown in Figure34) commonly plug with minimal WOR.
The Norsk-Hydro authors suggest that behavior such as in Figure 34 illustratesa “natural” anti-agglomerant mechanism because, “the difference in plugging behavioris attributed to the type and amount of natural surfactants present in the oil orcondensate. In general oils with little tendency to form stable emulsions have beenobserved to form hydrate plugs more easily than oils more prone to form stableemulsions.”
Rule-of-Thumb 11. Use of anti-agglomerants requires a substantialoil/condensate phase. The maximum water to oil ratio (volume basis) for the useof an anti-agglomerant is 40:60 on a volume basis.
The above rule-of-thumb is founded on two bases:1. At higher WOR than 40:60, the water-in-oil emulsion may invert to an oil-in-water
emulsion. If the water phase is external, hydrates will grow beyond small droplets.2. Coal slurry transport technology provides a maximum ratio of coal : liquid vehicle
of 40:60. Higher ratios increase the risk of having a non-transportable hydratephase, similar to a non-transportable coal slurry.
Hydrate Plug
Without Anti-Agglomerantes
With Anti-Agglomerantes
CondensateHydrates in Suspension
CondensateCondensate
Figure 33 - Anti-Agglomorants in Pipeline(From Sloan, 1998)
Figure 34 - Anti-Agglomerantes Effectiveness in Various Amounts of Water
(From Lingelam et al, 1994)
100
Not Tested
90 No Hydrate
Hydrate, No Plugs
80 Plugs
70
60 T = 0-4 oC
Watercut % P = 70 bar
50
40
30
20
10
0
0 5 10 15
Wt% MeOH
47
At the French Petroleum Institute, Behar et al. (1994) provided threeperformance examples of an anti-agglomerant inhibitor in a two inch pilot loop, for arecombined crude, a gas saturated oil, and a gas saturated condensate with WORratios of 0.3, 0.3, and 0.1 ft3/ft3 respectively. The last case is shown with and withoutanti-agglomerant inhibition in the Figures 35 and 36, respectively.
The gas consumption increases in both cases, indicating hydrate formationeven with anti-agglomerant inhibition. However the loop pressure drop (an indicatorof hydrate formation in a closed system) remains at a low value with inhibition (Figure36), while it increases rapidly without inhibitor in Figure 35. A low pressure dropindicates that the effective viscosity is small and that the fluid components flow readily.
Small amounts of surfactant are required relative to traditional inhibitors likemethanol. Behar et al. (1994) indicate that 1 wt% of an emulsifier is equivalent to 25wt% methanol. Economics should include such factors as surfactant cost, emulsionbreaking, and recovery, and environmental considerations.
Specific surfactants must be formulated and tested as emulsifying agents foreach composition of condensate. Many surfactants have been shown to promotehydrate formation. Significant technology was transferred from earlier studies ofenhanced oil recovery.
Undocumented reports from Shell report an inhibition chemical which providesinhibition at an order of magnitude lower concentration than the IFP chemical, withoutbeing condensate specific. Reportedly, this additive allows the hydrates to form beforetaking them into the condensate phase; some environmental concerns persist.
There is not a published commercial example of the use of an anti-agglomerantin an offshore hydrates application. Yet the method holds great promise, especially fordeep, highly subcooled systems and shutdown with cold restart situations.Weaknesses of the method include toxicity concerns, the need to break emulsions, andthe need to recover the expensive dispersant additive. Anti-agglomerant chemicals areproprietary and chemical structures, properties, and performance are not in the openliterature. The next decade will undoubtedly see major advances in these chemicals.
II.G.2.b Kinetic Inhibition. Kinetic inhibition of hydrate growth has a differentmechanism than that of anti-agglomerants. While there is evidence that the presenceof a liquid hydrocarbon phase aids inhibition, kinetic inhibitors prevent hydrate crystalnucleation and growth without emulsifying in a hydrocarbon phase. Prevention ofnucleation prevents hydrate crystals from growing to a critical radius. Growthinhibition maintains hydrates as small crystals, inhibiting progress to larger crystals.
Figure 37 shows the most common measure of kinetic inhibitor performance.The line marked Lw-H-V represents the hydrate formation line, as predicted by the gas
Figure 35 - Hydrate Formation with Plugging(From Behar et al, 1994)
0
10
20
30
40
50
60
70
0 10 20 30 40 50 60 70 80Time (min)
Tem
pera
ture
(o F);
Gas
Con
sum
ptio
n (m
Mol
)
0
0.5
1
1.5
2
2.5
3
3.5
4
Pre
ssur
e D
rop
(Psi
a)
Gas Consumption
Temperature
Pressure Drop
Plugging
WOR = 0.1 Ft3/Ft3
Figure 36 - Anti-Agglomerants Preventing Plugging(From Behar et al, 1994)
0
10
20
30
40
50
60
70
0 50 100 150 200
Time (min)
Tem
pera
ture
(o F);
Gas
Con
sum
ptio
n (m
Mol
)
0
0.5
1
1.5
2
2.5
3
3.5
4
Pre
ssur
e D
rop
(Psi
a)
Gas Consumption
Temperature
Pressure Drop
No Plugging
WOR = 0.1 Ft3/Ft3
20 40 60 80 10010
100
1000
10000
Temperature (oF)
Pre
ssur
e (p
sia)
Equilibriu
m Line(l w-H-V)
Start Experiment
Cooling
TeqHydrateOnset(Tonset)
(Tsubcooling)
Figure 37 - Subcooling as a Measure of Kinetic Inhibitor Performance(From Shuler, 1994)
∆T
48
gravity curve (Section II.C) or by HYDOFF (Section II.D), with hydrate formation tothe left and non-hydrate conditions to the right of the line. The horizontal line inFigure 37 represents a cooling curve for hydrate forming mixtures, such as may occurin a pipeline (Figure 7). The object of kinetic inhibition is to maintain the operatingcondition of a pipeline as far as possible to the left of the Lw-H-V line withoutformation of hydrate plugs during the residence time of the fluids in the flow line.
In Figure 37, subcooling (∆T) is the measure of the lowest temperature thatthe system can be operated relative to the hydrate formation temperature at a givenpressure. The maximum value of ∆T is determined by a laboratory and/or pilot plantexperiment, and the pipeline is operated at a smaller value of ∆T. The value of ∆Tappears to be pressure independent; however ∆T does depend upon the polymer,molecular weight, and the amount of salt, glycol, and alcohol present. Recent resultssuggest that water residence time can be as long as 30 days without hydrate formation,when the lowest temperature of the pipeline is at least 3oF less than the maximumsubcooling (∆Tmax) with a good kinetic inhibitor.
Kinetic inhibitors are commonly polymers with several chemical formulasshown in Figure 38. Each of the chemicals has a polyethylene backbone, connected topendant groups typically containing an amide (-N-C=O) linkage, frequently within afive- or seven-member ring. As the inhibitor adsorbs on the hydrate crystal, thependant group penetrates specific sites (cages) of a hydrate crystal surface while thepolymer backbone extends along the surface. In order to continue growing, the crystalmust grow around the polymer; otherwise crystal growth is blocked.
Figure 39 is a schematic of one type of kinetic inhibition. Adsorption of threekinetic inhibitor polymer strands are shown on a hydrate crystal surface. The “filledstars” on each polymer strand represent the pendant groups which dock at the “emptystar” sites on the hydrate crystal surface. As indicated on the figure, the subcooling∆T is directly proportional to the liquid-crystal surface tension (σ), but inverselyproportional to the length (L) between polymer strands.
If the amount of polymer adsorption increases, the distance L between thestrands decreases, resulting in an increased subcooling ∆T performance. Conversely,if the amount of inhibitor adsorption decreases (due to depletion by multiple smallhydrate crystals) the distance L between polymer strands increases, resulting in asmaller subcooling ∆T.
One of the first kinetic inhibitors developed was polyvinylpyrrolidone (PVP), apolymer whose structure is shown in Figure 38. Several companies have adopted theuse of PVP in onshore fields with a small subcooling (∆T) and short residence time.
Initial field tests of kinetic inhibitors were reported by ARCO (Bloys et al.,1995) and Texaco (Notz et al., 1995). Bloys reported the effectiveness of 0.3-0.4wt% VC-713 in a 17 day test in a North Sea pipeline. The pipeline (8 in. diameter, 9.4
Fkure 38 - Formulas of Some Kinetic Inhibitors (From Sloan, 1998)
PVCap
H3C ‘N’CH3
vc-713
Crys
tal S
urfa
ce
Poly
mer
Cha
in
∆TC L
≤⋅
4σ
Figure 39 - Polymer Adsorption in Hydrate Crystal (From Larsen, 1994)
L L
49
km long) had a flow rate of 20 MMscf/d, 0.5 bbl/MMscf condensate and 0.2bbl/MMscf condensed water at a subcooling between 1oC and 9oC. Bloys suggestedthat economics were very favorable for new developments, but marginal for retrofitsof systems with traditional inhibitors such as monoethylene glycol.
Texaco’s Notz et al. (1995) indicated successful use of polyvinylpyrrolidone(PVP) in several wells and flow lines in Texas and in Wyoming, concluding that PVPwas in routine use in some Texaco fields. Notz further reported that PVP (at less than1 wt%) was effective in replacing methanol (at concentrations from 10 to 60 wt% infree water) resulting in savings of as much as 50%. See Texaco Case Studies C.13and C.14 in Appendix C.
Rule-of-Thumb 12. PVP may be used to inhibit pipelines with subcooling lessthan 10oF for flow lines with short gas residence times (less than 20 minutes).
Rule-of-Thumb 12 comes from Texaco’s Reliability Engineering: Gas Freezing& Hydrate Study, a handbook for field personnel by Todd et al. (1996) which reflectsTexaco operating kinetic inhibitor practice with approximately 30 flow lines from theirBrookeland field.
Kinetic inhibitors more effective (but more expensive per pound) than PVP(illustrated by the other chemical formulas in Figure 38) have a seven-member ringpendant group in place of the five-member PVP pendant ring. The better kineticinhibitors provide additional subcooling with long water residence times.
Rule-of-Thumb 13: VC-713, PVCap, and co-polymers of PVCap can be used toinhibit flow lines at subcooling less than 18oF, with water phase residence timesup to 30 days.
Rule-of-Thumb 13 comes from commercial use of kinetic inhibitors, asindicated in the below case study.
_____________________________________________________________________Case Study 7: North Sea Use of New Inhibitors
On July 22, 1996 British Petroleum (BP) initiated continuous commercial useof kinetic inhibitors (called threshold hydrate inhibitors, THI) in flowlines in the WestSole gas export lines (Argo et al, 1997). This followed from an extensive set of fieldtrials carried out in the Ravenspurn to Cleeton wet gas line (Corrigan et al., 1996).
BP began THI use in a 16 inch I.D., 13 mile long pipeline from threeRavenspurn platforms to Cleeton. At the time of the trial the maximum flow rate was195MMscf/d. For the purpose of the trial the flow rate was cut back to 90mmscf/d toput the line as far into the hydrate region as possible (16oF of subcooling). Three trialswere carried out, all of which were successful. The trials included extensive periods of
50
shut-in, up to 7 days with successful restart. A typical water production rate was 1.6bbl/MMscf with a line pressure of 1088 psia and a low temperature of 48oF. The THIdose rate was 3000-5000 ppm based on the free water phase. See Corrigan et al.(1996) for further details.
Currently two lines (24 inch and 16 inch I.D., 35 miles long) from West SoleA,B, and C and Hyde are being inhibited with THI. Water residence times can be aslong as 2-3 weeks, and the lines are 11oF inside the hydrate region at operationalconditions. The gas is very lean producing very little condensate. Water content islow and free water comes mainly from condensation. Due to the low amounts ofwater and condensate, this is an atypical case, but nonetheless represents a severe testfor kinetic inhibitors.
Water production from all four West Sole platforms is 150-200 bbl/d, or about0.3 bbl/MMscf with 250 MM scf/d total produced from the 3 West Sole platforms andthe remainder from the Hyde platform. The condensate rate is also 0.3 bbl/MMscf.The THI pumping rate per platform is 2-3 liters/hr of solution which contains about15wt% active ingredient. The target injection rate is 3000 ppm based on the freewater phase._____________________________________________________________________
II.G.3. Guidelines for Use of Chemical Inhibitors
Table 5 is a stepwise protocol to determine whether the use of inhibitors mightbe suitable, modified from the original suggestions by Edwards of BP (1997) and T ROil Services (Grainger, 1997). It should be emphasized that, before field application,experimental data should be obtained, particularly if kinetic inhibition is beingconsidered. The below protocol provides preliminary steps for such experiments.
_____________________________________________________________________Table 5. Guidelines for Use of Kinetic or Thermodynamic Inhibitors
1. If the field is mature, record the current hydrate prevention strategy. Record theexisting or planned procedures for dealing with an unplanned shutdown. Provide ageneric description of the chemistry of the scale and corrosion inhibitors used.
2. Obtain an accurate gas, condensate, and water analyses during a field drill test.
Estimate how these compositions will change over the life of the field. Estimatethe production rates of gas, oil, and water phases over the life of the field.
3. Generate the hydrate pressure-temperature equilibrium line with several prediction
methods. If the operating conditions are close to the hydrate line, confirm theprediction with experiment(s).
51
4. Determine the water production profile over field life (see Table 6 example). 5. Consider the pipeline topography along the ocean floor to determine where water
accumulations will occur at dips, resulting in points of hydrate formation. 6. Simulate the pipeline pressure-temperature profile using a simulator such as
OLGA� or Pipesim� to perform hydraulic and heat transfer calculations in the well,flow lines, and separator over the life of the field.
7. Determine the water residence times in all parts of the system, especially in low
points of the pipeline. 8. Estimate the subcooling ∆T (at the lowest temperature and highest pressure)
relative to the equilibrium line over all parts of the system, including fluidseparators and water handling facilities. List the parts of the system which requireprotection.
9. If ∆T < 14oF, consider the use of kinetic inhibitors. If ∆T > 14oF, consider the use
of standard thermodynamic inhibitors or anti-agglomerants (no one has used anti-agglomerants commercially as of January 1, 1998).
10. Perform economic calculations (capital and operating expenses) for four options
(a) drying, (b) methanol, (c) monoethylene glycol, and (d) kinetic inhibitors. 11. Determine if inhibitor recovery is economical. 12. Design the system hardware to measure: (a) temperature and pressure at pipe inlet
and outlet (b) water monitor for rates at receiving facility, and (c) the belowchemical check list
a) Has the inhibitor been tested with systems at the pipeline temperature andpressure?
b) Consider the environmental, safety, and health impact of the chemical.c) Determine physical properties such as flash point (should be < 135oF),
viscosity ( should be <200 cp at lowest T), density, and pour point ( shouldbe >15oF).
d) Determine the minimum, maximum, and average dosage of inhibitor.e) Determine the storage and injection deployment methods.f) Determine the material compatibility with gaskets, seals, etc.g) Determine compatibility with other production chemicals.h) Determine the compatibility with the process downstream including cloud
point, foaming, and emulsification tendencies.
52
At an early stage in the inhibitor design process it will be worthwhile toconsider obtaining laboratory data and involving a service company to provide fieldsupport of process hydrate inhibition._____________________________________________________________________
Hydrate inhibition occurs in the water phase and is dependent on the amount ofwater production and the salt concentration. Because the amount and concentrationof pipeline water depends heavily upon produced water, reservoir engineers shouldprovide the best estimate of produced water and salt concentrations over the life of thefield. The second source of water, condensed water, can be estimated from gas watercontent as illustrated in Section II.C.3.a and in Figure 10.
Edwards also provided one possible scenario for water production over a fieldlife, given in Table 6. The below scenario for a North Sea pipeline indicates a non-intuitive situation. The pipeline initially operates with a low inhibition need, in mid-lifethe pipeline requires inhibition, in the final stages of life, the pipeline does not requirehydrate inhibition.
_____________________________________________________________________Table 6. One Scenario for Pipeline Water Over Field Life
1. At the beginning of field life, water production may be low, so that only a smallamount of condensed water can be responsible for hydrate problems. The fieldmay be operating with a large subcooling ∆T, but low dosages of chemicals arerequired by low amount of water production. However, there are counterexamples of fields which begin producing water early in their life. Only fluidmeasurements can assess this difference.
2. At field mid-life, water produced down the line (if there is no upstream separation
facilities) will increase. Both produced water and condensed water may besubstantial. Total water may double or triple, but the condensed water amountmay be sufficient to dilute the solution to low salt concentrations, so thatmaximum inhibitor injection rates may be required. Over a field lifetime, typicalsalt concentration from produced water may vary from 0% to the reservoirconcentration.
3. At the end of field life there may be 10 times as much water, but it is mostly saline
production, Both the increase in water salinity and the pressure decline of the fieldmay take the production fluids outside the hydrate P-T region.
4. As an example, one BP field is forecast to dip into and out of the hydrate
formation region over its life._____________________________________________________________________
53
II.G.4. Heat Management
The discussion in this section has been excerpted from DeepStar reports CTRA601-a,b,c,d, CTR 223-1, from Aarseth (1997), and from discussions with Statoilresearchers.
The retention of reservoir heat is one of the most efficient means of hydrateprevention. Because all reservoirs contain water and because water acts as a heat sinkdue to a high heat of vaporization, fluids at the wellhead are typically at temperaturesfrom 175oF to 212oF. When the reservoir fluid flows through a deep ocean pipelinewith an outer temperature at 40oF, the temperature can quickly cool into the hydrateregion as determined by the heat transfer coefficient (U) between pipe and ocean.
_____________________________________________________________________Case Study 8. Pipeline Temperature with Heat Loss
Figure 40 (from DeepStar Report CTR 223) shows an offshore pipelinetemperature as a function of length, at various values of U, between the pipeline inlettemperature (140oF) and a separator 50 miles away. The pipeline in the figure wasassumed to be 50% buried and had a water flow of 1,527 bbl/d, a gas flow of 30.76MMscf/d, and an oil flow of 22,723 bbl/d.
In Figure 40 the lowest, dashed line shows the temperature of the ocean withlength. The upper lines represent the pipeline temperature with no heat loss throughthe pipe wall, with the temperature drop being due to expansion. However, with heatloss through the pipewall, the temperature drops dramatically. With overall heattransfer coefficients of U = 0.17 and U = 3.3 BTU/hr-ft2-oF, the separator temperatureis 70oF or 50 oF, respectively. Hydrates can easily form at these temperatures,particularly at the higher pressures (densities) necessary to make pipeline transporteconomical. It is concluded that a lower heat transfer coefficient is needed to preventhydrate formation._____________________________________________________________________
The temperature profiles in the above case study are for a flowing pipeline. Ifthe pipeline were shut-in, the system would rapidly cool to the ambient conditionsrepresented by the dashed line at the bottom of Figure 40. At the low ambienttemperatures, hydrate problems are particularly severe and blockages may occur,particularly when the system is re-started.
If hydrates form in an insulated pipeline, the pipeline may be depressurized toachieve a hydrate equilibrium temperature just above 32oF, so that heat will flow intothe hydrates from the ocean, which has a temperature around 40oF. In such cases, theinsulation is a hindrance or barrier which prevents heat flow from the ocean, making
Figure 40 - Pipeline Temperature vs. Change in Heat Conductivity of Pipeline
(From Deepstar CTR 223, 1995)
0
20
40
60
80
100
120
140
160
0 50000 100000 150000 200000 250000 300000
Pipeline Length (ft)
Pip
elin
e T
emp
erat
ure
(oF
)
Heat LossThrough Pipewall
Ambient Conditions
Little Heat LossThrough Pipewall
U=0.17 Btu/(hr ft2 oF)
U=3.3 Btu/(hr ft2 oF)
54
hydrate dissociation much more difficult. As a consequence it is good operatingpractice to inject large quantities of MeOH or MEG into the pipeline before a plannedshut-in.
Hydrates can be prevented in pipelines by three types of heat control:
1. burying the pipeline to provide heating and insulation by the ocean floor,2. insulating the pipeline, using non-jacketed insulation, pipe-in-pipe systems,
and bundling systems, or3. heating the pipeline.
Pipeline burial is a good means of providing pipeline insulation and protection.The degree of insulation depends upon the thermal gradient in the earth along thepipeline route, the pipeline depth, and the water temperature. Expenses for providinga trench and burial system for pipelines may be very high, particularly at great depths.On the other hand, heat control systems through pipeline insulation or heating may belaid with the pipeline from a barge. Pipeline insulation and heating methods are givenconsideration in design, but insulation alone offer no protection for long-term shut-ins.
II.G.3.a Insulation Methods. Figure 41 shows the three categories of insulatedpipelines: (a) non-jacketed, (b) pipe-in-pipe, and (c) bundled flowlines. The non-jacketed system (Figure 41a) consists of an insulated pipe with a coating. Theminimum overall coefficient achievable with a non-jacketed system is 0.3 BTU/hr-ft2-oF (CTR A601-a) and costs are typically $50-$300/ft. for pipes with diametersbetween 8 inches and 12 inches.
The pipe-in-pipe (PIP) system (Figure 41b) is the most thoroughly tested of thethree types. In this system the flow pipe is within an outer pipe, with either insulationor vacuum between the two pipes, sometimes aided by a reflecting screen in theannulus. With a 3-4 inch insulation layer, the PIP system can provide an overall heattransfer coefficient (U) of 0.14 - 0.6 BTU/hr-ft2-oF.
Figure 41c, shows a bundled line with two or more flowlines and a start-upwater line with an insulator, all in an outer casing. Bundles are fabricated on shore inlengths up to 10 miles and towed to their offshore position, currently at water depthsof up to 5,000 ft. Overall heat transfer coefficients as low as 0.1 BTU/hr-ft2-oF can beachieved.
Figure 42 (from DeepStar Report II CTR 223) shows the increase intemperature at the platform riser as a function of insulation thickness, with twopipelines flowing together compared to an individual flow, when each line has a waterflow of 1,527 bbl/d, a gas flow of 30.76 MM scf/d, and an oil flow of 22,723 bbl/d.The addition of a second flowline can reduce the insulation thickness required to
Fipure 41 - PiFeline Insulation Methods (From Deenstar CTR A601-a, 1995)
Insulation Insulation (Max. 3 in.)
Steel Flowline A) Non-Jacketed Insulation System B) Pipe-in-Pipe Insulation Svstem
Figure 42 - Riser Temperature vs. Thickness(From Deepstar CTR 223, 1995)
70
75
80
85
90
95
100
105
110
0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2
Insulation Thickness (inches)
Tem
per
atu
re (
oF
)
Two Pipeline Flows
One Pipeline Flow
Flow to Each Pipeline22,723 Bbl/day oil & condensate,
30.76 MMSCF/D gas, and1,527 Bbl/D water
55
obtain a given riser temperature, or the second flowline will provide a higher risertemperature for a given insulation.
Figures 43 and 44 (from DeepStar Report CTR A601-a) compare the cost ofthe three above types of insulation for water depths of 6000 ft. over 60 miles at oilproduction rates of 25,000 and 50,000 bbl/d, respectively. If an average U = 0.3BTU/hr-ft2-oF is required with a flowline pressure of 4000 psia, bundled flow lines aremore cost effective.
II.G.3.b Pipeline Heating Methods. DeepStar Report CTR A601-b concludesthat, “where pipeline depth precludes depressurization below the hydrate formationpressure, heating may be the only option to clear a hydrate plug.” Yet as noted inSection I, heating a hydrate plug can be very dangerous. DeepStar Report CTRA601-c concludes that pipeline heating will be very expensive, “at least 1MW ofpower is required for a 20oC (36oF) increase of a 10 inch pipeline 15 miles long.”
In the future Statoil will use heating more extensively in order to reduce theamount of methanol or other chemicals used. Bundles will be used in 1998, and directheat thereafter. The Chevron/Conoco Britannia project will start in the North Sea in1998 using a bundled line to heat fluids. The three common means of heatmanagement are (a) bundling hot water lines (for 10 km and return) in production linesto prevent hydrate formation (b) Combipipe (shown in Figure 45) for inductionheating, with current flowing through 3 cables outside of pipe but within insulation,with corrosion protection,), (c) direct electrical heating for 50-60 km long lines(shown in Figure 46) in which the pipeline is the primary conductor with a currentreturn line at 1m in parallel to the pipeline. It should be noted however, that suchheating tools are in the planning stage and commercial use has yet to be documented.
II.H. Design Guidelines for Offshore Hydrate Prevention
The below hydrate prevention paradigm is a collection of Rules-of-Thumbwhich provide general guidelines for offshore design. These design Rules-of-Thumbare for hydrate prevention in the three parts of the system where hydrates most oftenoccur (shown in Figure 47): the well, the pipeline, and the platform. Many of theseguidelines result from Section III on Hydrate Remediation.
1. Before embarking on a hydrate prevention design, it is imperative to have a reliablehydrate equilibrium curve (Sections II.C and II.D) which represents the gas,oil/condensate, and water compositions over the life of the field. If possible thehydrate formation curve should be verified via an independent prediction orhydrate formation experiment.
2. Simulate the pressure-temperature profile in the well, flow lines and platform at the
worst case (usually during winter months) over the life of the field. Estimate the
Figure 43 - Cost vs. Overall Heat Transfer Coefficent(Depth - 6000ft. Prod. Rate - 25,000 BOPD)
(From Deepstar CTR A601-a, 1995)
0
100
200
300
400
500
600
700
800
900
0 0.1 0.2 0.3 0.4 0.5 0.6
U-Value (Btu/hr-sqft-oF)
Co
st($
/ft)
14" Non-Jacketed2x10" Non-Jacketed14" PIP3x8" PIP3x8" Bundled3x8" Vacuum Tube3x8" Non-Jacketed2x10" PIP2x10" Bundled
Figure 44 - Cost vs. Overall Heat Transfer Coefficent(Depth - 6000ft. Prod. Rate - 50,000 BOPD)
From Deepstar CTR A601-a, 1995)
0
200
400
600
800
1000
1200
0 0.1 0.2 0.3 0.4 0.5 0.6
U-Value (Btu/hr-sqft-oF)
Co
st($
/ft)
18" Non-Jacketed2x12" Non-Jacketed18" PIP3x10" PIP3x10" Bundled3x10" Non-Jacketed2x12" PIP2x12" Bundled
PipelinePipeline
Insulation
Insulation
Hot WaterInput Line
Cold WaterReturn
A) Bundled Pipeline
Flowline
Pipewall withCorrosion Protection
HeatingCables
ThermalInsulation
B) Combi- Pipe
Figure 45 - Heating Through Bundling and Combi-Piping
Pipeline
1 meter
Current Return Wire
Electric Current Electric Current
Figure 46 - Direct Electric Heating
Figure 47 - Offshore Well, Transport Pipeline, and Platform
Downhole SafetyValve
Well withX-Mas Tree
Riser
SEP.
CO
MP.
DR
Y
ExportFlow
lineTransport Pipeline(2-60 miles in length)
Platform
Bulge from Expansionor Topography
Ocean
Mudline
- Depth 6000 ft
56
water residence times at all points in the system. Account for both normal cooling(e.g. in pipelines as in Example 2 of Section II.A) and Joule-Thomson expansionsacross restrictions (e.g. in wells, chokes, and control valves as in Section II.F).
3. Estimate the subcooling ∆T (at the lowest temperature and highest pressure) at
each point in the process relative to the hydrate equilibrium curve. Hydrates mayform in systems with subcooling ∆T’s less than 2-4oF.
4. Where subcooling is unavoidable, determine the type of hydrate inhibition, such as
chemical inhibitor injection (Sections II.G.1, II.G.2, II.G.3, particularly Table 5),or heat management (Section II.G.4). Choose the inhibition method with regard toboth prediction ability and operating experiences. Consider providing a heaterprior to the platform choke and separator.
5. Eliminate subcooling points of likely hydrate formation. Design pipelines to
minimize buckling and protrusions from mudlines which might promote cooling. 6. Design large pressure drops with either dry gas or expansions at high temperature
points in the process. Where large expansions of wet gas are unavoidable, (e.g. atchoke valves) provide methanol injection capability upstream of the restriction.
7. Eliminate points of water accumulation, such as upslopes in pipelines or “S”
configurations in risers. Where pipeline topography ensures water accumulations(e.g. upslopes in lines, etc.) provide for frequent pigging and consider placingmethanol injection prior to the accumulation points.
8. Eliminate points of hydrate accumulation from a mechanical perspective. Hydrate
crystals in a line may be considered to accumulate (and plug) wherever light sandparticles might accumulate, such as at blind flanges at turns, elbows, screens andfilters, upstream of restrictions etc. Avoid unnecessary bends. Bend radii less than5 times the pipe diameter should be avoided to facilitate coiled tubing entry. Ariser tube radius should be from 20-80 ft.
9. With a high probability hydrates will form over the system lifetime. Provide
hydrate remediation methods (see Section III for justification) in the design.
a) For pipelines, safe remediation often implies depressurization from bothends of a hydrate plug. Optimally, multiple access points in a pipeline (seeb) are invaluable in locating and remediating hydrate and paraffin plugs.Alternatively dual production lines should be used to provide fordepressurization of wellheads from the upstream side of a pipeline plug.
As a second best method, provide for depressurization through a wellhead
service line (for corrosion, paraffin, or hydrate inhibitor injection) withbypass capability for checkvalve(s) at the point of injection. As a minimum
57
a spare flange and valve should be provided at the wellhead or manifold, sothat depressurization can be done via connection to offshore productionvessel (see ARCO Case Study 14 in Section III.C.1.b) Technology is notyet available for location of the end of plugs or the safe heating of plugs inocean pipelines.
b) Subsea access points should be considered at the well manifold and at 4
mile intervals along the pipeline, as shown in Figure 48. Such access pointswill facilitate (a) the location of a hydrate (b) venting of excessive fluidhead from plugs in deepsea lines, (c) injection of hydrate inhibitors, (d)coiled tubing entry, and (e) pig launching.
c) In wells, hydrate remediation occurs by approaching one end of a plug via
chemical injection, depressurization, heating, or coiled tubing. Case Study16 in Section III.C.3 indicates that normal well lubricators can be used atthe swab valve with careful balancing of pressure.
d) On the platform hydrate plugs may be located using tools such as a
thermocamera (see Figure 54 of Section III.B.1.b). With the accuratelocation of the plug ends, remediation may be done through chemicalinjection, heating, or depressurization.
Fiqure 48 - Pre-Installed Access Ports on PipeLine (From Deepstar A-208-1, 1995)
Yorkover Vessels
\
access Port Functions I
Coiled Tubing Entry -Surface -suLxeo.
Inject Fluid Into Pipeline
Vent Fluids From
Pipeline - Hydrate Renoval
58
III. Hydrate Plug Remediation
Perhaps the best way to remove a hydrate blockage in a flow channel is to usethe experience of those who have removed similar blockages. In addition to thosecase studies in the body of the handbook, Appendix C details 27 case histories ofhydrate removal in flow lines. Table 7 provides an overview of Appendix C casehistories.
Rule-of-Thumb 14: Hydrate blockages occur due to abnormal operatingconditions such as well tests with water, loss of inhibitor injection, dehydratormalfunction, start-up, shut-in, etc. In all recorded instances1 pipeline plugs duesolely to hydrates were successfully removed and the system returned to service.
No pipelines were abandoned or replaced due to a hydrate plug, as issometimes the case for paraffin plugs. However since every hydrate plug is unique,individual case studies are anecdotal in nature. A very large number of anecdotalstudies is required before detailed remediation Rules-of-Thumb can be stated withconfidence.
Fortunately three systematic studies of hydrate plugs provide substantialguidelines for remediation. In 1994 Statoil purposely formed/removed over 20hydrate plugs in a 6 inch gas/condensate line over a 9 week period (Case StudiesC.15,16,17 in Appendix C). During 1995-6 uninhibited plug formations were studiedas baselines for new inhibitors. DeepStar IIA Report A208-1 Methods to ClearBlocked Flowlines (December 1995) was compiled by Mentor Subsea to document 16hydrate blockage cases and 39 paraffin blockage cases. In -February 1997 SwRI(Hatton et al., 1997) formed and dissociated hydrates in a Kerr-McGee field line,resulting in three significant tests (Case Studies C.25,26,27) with extensiveinstrumentation at five pipeline points.
Much of the information in Section III on hydrate remediation was excerptedfrom the above three systematic studies, supplemented by the literature and personalinterviews relating to hydrate blockages. The section is organized to provide answersto the following questions:
III.A. How do Hydrate Blockages Occur?III.B. How Can Hydrates be Detected?III.C. How Can Hydrate Plugs be Removed?III.D. What Remediation Questions Remain to be Answered?
1 An exception was the LASMO Staffa subsea field in the North Sea, which was abandoned in 1995due to low production problems with combined waxes and hydrates. See Case Study C.6. for furtherhistory on this field, which included a 1 mile flowline replacement.
Table 7 Summary of Hydrate Blockage Experiences in Appendix C
Field/ Line Line WD Time Extent of Control Method Operations Removed? CurrentCase/Operator Region Size Type (ft) Restriction before Plug before Plug Prev. Method
1. Placid GC 29 16" Gas Cond. 200 ft 1989 Complete None Flowing Depressurize Gas Dehydration
MeOH Inj.
2. Chevron Wyoming 4" Gas Cond. 0 Winter Complete Heating Tape & Flowing Depressurize MeOH Inj.
Insulation Heat MeOH
3. Chevron GOM Gas Lift 0 Winter Complete None Flowing Inj. MeOH Inj. MeOH
Inj. Lines Vary Flow Rate
4. Chevron Oklahoma 4" Gas Sales 0 1995 Partial None Depressurize Remove Restriction
Inj. MeOH @ Flow Meter
Heat Gas MeOH during
Winter
5. Chevron Canada 6" Gas cond. 0 Winter Complete None Shut in for Depressurize Depressurize after
Export Several Days Heat w/ 24 Hours S/I
Welding Rig
6. Lasmos North Sea 8" Multiphase ? 1994 Complete MeOH Flowing Replaced 2km Same as before
blocked section Planning to abandon
7. Texaco GB 189 2-3/4" Gas 725 ft 1995 Complete None Flowing Depressurize Inj. MeOH
Inj. MeOH Gas Dehydration
8. Texaco GC 6 3/4" Gas 600 ft 1992 Partial None Flowing Depressurize Inj. MeOH
Inj. MeOH Gas Dehydration
9. Texaco North Sea 1/4" Instrament - Complete None Flowing Inj. MeOH Occasionally Inj. MeOH
Valve
Field/ Line Line WD Time Extent of Control Method Operations Removed? CurrentCase/Operator Region Size Type (ft) Restriction before Plug before Plug Prev. Method
10. Elf Norge N.E. Frigg 16" Gas Cond. - 1990 Partial MeOH Flowing Depressurize MeOH Injection
Inject MeOH
11. Marathon EB 873 - Gas Export 800 ft 1995 partial Inadequate Flowing Inject more Maintain
MeOH MeOH MeOH Inj.
12. Philips Cod N. Sea 16" Gas & Cond.
Export - 1978 Complete MeOH Pig Stuck Depressurize MeOH Inj.
Pigging MeOH Inj. Dehydrate Cond.
13. Texaco Wyoming - Gas 0 1995 Complete MeOH Field Test Depressurize Comb. of KI
and MeOH
14. Texaco East Texas 4"-6" Gas 0 1995 Complete MeOH Field Test Depressurize Comb. of KI
and MeOH
15. Statoil Tommeliten 6" Gas Cond. - 1994 Complete MeOH Inj. Flowing/ Depressurize Continue
(Experimental) North Sea Shut-in/ Inj. MeOH MeOH Inj.
Re-start
16. Statoil Tommeliten 6" Gas 11.5 km 1994 Complete MeOH Field Study Depressurize
Condensate Inj. MeOH
17. Statoil Tommeliten 6" Gas 11.5 km 1994 Complete None Field Study Depressurize
Condensate
18. Oxy North Sea - Gas - - Complete MeOH Flowing Depressurize Ensure Proper
Condensate MeOH Inj. MeOH Inj.
Field/ Line Line WD Time Extent of Control Method Operations Removed? CurrentCase/Operator Region Size Type (ft) Restriction before Plug before Plug Prev. Method
19. Amoco North Sea - Gas Export NA - Complete None(Dry) Flowing Depressurize Ensure
MeOH Inj. Dehydration
20. Petrobras Brazil - Manifold NA - Complete Ethanol Start-up Depressurize Drain Manifold of
Ethanol Inj. Water before Start-up
21. Exxon California - Well NA 1989 Complete None Drilling - -
22. Exxon Gulf of Mex - Well NA 1989 Complete None Drilling - -
23. Exxon S. America - Well NA 1993 Complete None Testing Coiled Tubing -
Hot Glycol
24.Exxon Gulf of Mex - Well NA 1993 Complete Methanol Shut-in Abandoned
25. Kerr-McGee Wyoming 4" Gas/Condns Land 1997 Complete Methanol Shut-in Depressurize
26. Kerr-McGee Wyoming 4" Gas/Condns Land 1997 Complete Methanol Shut-in Depressurize
27. Kerr-McGee Wyoming 4" Gas/Condns Land 1997 Complete Methanol Shut-in Depressurize
59
III.A. How Do Hydrate Blockages Occur?
Figures 3 and 47 in Section II each show a simplified offshore process betweenthe well inlet and the platform export discharge. Section II.A illustrates hydrateprevention design where virtually all hydrates occur - namely in (a) the well, (b) thepipeline, or (c) the platform. Before the well, high reservoir temperatures preventhydrates; platform export lines are dry, with insufficient water to form hydrates.
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.C. andII.D. In order for hydrates to form, the system temperature and pressure must firstenter into the hydrate formation region, either through a normal cooling process(Example 2 and Figure 6 and 7) or through a Joule-Thomson process (Section II.F).
The rate of hydrate formation region is a function of the degree of subcooling(∆T see Figure 37 in Section II.G.2.b) relative to the hydrate formation line. Hydratescan form with subcooling ∆T’s less than 2-4oF, particularly in industrial systems withcontaminants like sand, weld slag, etc. present to serve as nucleation centers.However, hydrates with such a low degree of subcooling will form more slowly than insystems which have a subcooling of 10oF or more.
III.A.1 Concept of Hydrate Particle and Blockage Formation.
All natural gas hydrates are approximately 85 mole% water and 15% naturalgas. Hydrate formation always occurs at the hydrocarbon-water interface, becausethis 85:15 ratio is far in excess of the solubility of gas in the bulk water (< 0.06 mole%) or water in the bulk gas (< 4%). This exceptionally low mutual solubility is theresult of water hydrogen-bonding (see Sloan, 1998, Chapter 3).
When hydrate particles occur in a static system, a solid hydrate shell forms animpenetrable barrier at the hydrocarbon-water interface which prevents further contactof the hydrocarbon and water phases. Diffusion through the solid is extremely slowand hydrate fissures or cracks provide the only means for further contact of the waterand hydrocarbon. Due to the hydrate formation barrier at the interface, natural gashydrate particles have water as an occluded phase. Infrequently, when gas is bubbledthrough water, gas is the occluded phase within a hydrate shell.
In an turbulent system such as a pipeline, high agitation rates provide forsurface renewal, which can form hydrate particles and agglomerations to build up andobstruct pipe flow. Such a build-up is one major concern of this section.
Rule-of-Thumb 15: In gas-water systems hydrates can form on the pipe wall. Ingas/condensate or gas/oil systems, hydrates frequently form as particles whichagglomerate and bridge as larger masses in the bulk streams.
60
Rule-of-Thumb 15 was obtained through multiple studies on flow loops/wheelsat Statoil’s Research Center in Trondheim, Norway. In gas systems, water may splashor adsorb on the pipe wall where hydrate nucleation and growth may occur. In anoil/condensate system, the light hydrocarbon liquid above the water prevents splashingand causes hydrate particle formation and agglomeration at the liquid-liquid interface.
In a black oil system, often only a small amount (less than 5 volume %) ofwater forms hydrates, but all the water and condensate are trapped in the open, poroussystem and can form a blockage (Urdahl, 1997). In Statoil’s Tommeliten Fieldblockages formed from a hydrate slurry with < 1 volume % of the water present. Suchresults are fluid dependent; while some oil/water systems convert to hydrates almostimmediately with fairly low water conversion, other oil systems are more difficult toconvert, but practically all water might be transformed to hydrates.
Rule-of-Thumb 16: Agglomeration of individual hydrate particles causes anopen hydrate mass which has a high porosity (typically >50%) and is permeableto gas flow (permeability to length ratio of 8.7 - 11 × 10-15 m). Such an openhydrate mass has the unusual property of transmitting pressure while being asubstantial liquid flow impediment. Hydrate particles anneal to lowerpermeability at longer times.
Rule-of-Thumb 16 was obtained through both field and laboratory studies atStatoil’s Tommeliten Gamma field and SINTEF’s research center (Berge et al., 1996).Plug porosity is determined by forming conditions and fluid effects; some plugs canhave porosities considerably higher than 50% while other plug porosities can beconsiderably lower. Because liquid surface tension is much higher than that of gas byabout a factor of 1000, hydrate plugs are much less permeable to liquid than to gas.
Figure 49a from Lingelem et al. (1994) of Norsk Hydro is a schematic of thecase of hydrate formation along the wall periphery in a gas system. This slow buildupof hydrates along the wall may be characterized by the gradual increase in line ∆Pwitnessed in 2 of 3 DeepStar field tests in a Wyoming gas-condensate line (Hatton etal., 1997).
Figure 49b shows the case of hydrate formation as agglomerating or bridgingparticles in a condensate or oil system, providing the open, porous structure. TheStatoil experience suggests that Figure 49b represents the more common case inhydrate formation. However, there are two schools of thought about hydrateformation; (1) the gradual buildup of hydrate formation on the walls, resulting in theless porous plugs seen in a few, thoroughly instrumented DeepStar field tests (SeeCase Studies C.25, C.26, and C.27) and the multitude of Statoil studies whichsuggests a high porosity, bridging hydrate structure may be the norm (See CaseStudies C.15, C.16, and C.17).
Figure 49a - Hydrate Accumulation in Gas Pipeline(From Lingelem et al, 1994)
Flow
Gas Pipeline
Hydrate Water
Initial 1 Hour 3 Hours 5 Hours
CondensatePipeline
Figure 49b - Hydrate Accumulation in Condensate Pipeline(From Lingelem et al, 1994)
Hydrate Plug
Complete PlugPartial Plug
61
The state-of-the-art of hydrate studies in field pipelines is too small todetermine the causes and frequency of either type of hydrate buildup. It is apparentfrom the small number of studies however, that a wide range of hydrate porosities maybe attained.
The porosity/permeability of hydrate plugs largely determines theirremediation. For example, if a hydrate plug is depressurized from only one end, flowthrough the plug will cause Joule-Thomson cooling just as in Example 11, so that thedownstream side of the plug may be in the hydrate formation region at the lowertemperature. This effect has been observed at the Tommeliten field (Berge et al.,1996) and provides both technical and safety reasons for depressuring a plug fromboth sides. However, Case Studies C.25, C.26, and C.27 detail safe techniques fordepressuring one side of a hydrate plug in DeepStar Wyoming field studies by SwRI(Hatton et al., 1997).
Figure 50 shows two types of pressure drop (∆P) increases which occur withhydrate blockage of lines. At the left, Figure 50a shows the gradual increase in ∆Pwhich would occur if hydrates formed an ever-decreasing annulus as shown in Figure49a. Figure 50b shows the more typical case of multiple spikes in ∆P before the finalplug forms; these spikes indicated that particles are forming blockages and releasing,as depicted in the agglomeration of particles in Figure 49b.
III.A.2 Process Points of Hydrate Blockage.
The above conceptual picture of hydrate formation reinforces field experiencesregarding points in the process shown in Figure 48 where hydrate formation occurs.For example, subcooling will occur with pipeline protrusions from mudlines so dips inpipelines should be minimized. Large pressure (e.g. at orifices/valves) should beavoided.
Points of water accumulation, such as “S” configurations in pipelines or risers,should also be minimized. Where pipeline topography ensures water accumulations(e.g. upslopes in lines, etc.) one may consider providing pigging inhibitor injectionpoints to accommodate the accumulation. Hydrate particles in a line may beconsidered to accumulate (and plug) wherever light sand particles might accumulate,such as at blind flanges at elbows, short radius bends, screens and filters, upstream ofrestrictions etc.
It is often unavoidable to design and to operate hydrate-free systems. In suchcases it is important to identify likely points of hydrate formation, so that hydrateprevention (or dissociation) can be addressed in the original design or in systemoperation through dehydration, heating, inhibitor injection, depressurization ormechanical removal.
Figure 50 - Pipeline Pressure Drops Due to Hydrates
Atypical Typical
Pipe
line
Pres
sure
Dro
p
Pipe
line
Pres
sure
Dro
p
Time Time
50a) 50b)
62
III.B. Techniques to Detect Hydrates.
When partial or complete blockages are observed in flowlines, questionsalways arise about the plug composition. Is the blockage composed of hydrates,paraffin, scale, sand, or some combination of these? Such questions are more easilyanswered with line access, as on a platform where a number of detection devices (e.g.thermocamera, gamma ray densitometers, or acoustic sensors) can be used asindicated in Section III.B.1.
Indications of the blockage composition are obtained through combinations of(1) separator contents and pig (sphere or ball) returns as direct indicators and (2) linepressure drop as an indirect indication. Separator contents and pig returns provide thebest indication of pipeline contents and should be regularly inspected, even whenblockages are not a problem. Separator discharges and the pig trap provide valuableinformation about line solids such as hydrates, wax, scale, sand, etc. and may be usedas an early warning of future problems.
A less direct flow indicator is line pressure drop buildup, which differs forhydrates and for paraffins. Pressure drop increases are usually more noticeable thanflow rates changes. With the exception of hydrate formation from gases withoutoil/condensate (with a typical pressure drop schematic in Figure 50a), hydrates usuallycause a series of sharp spikes (Figure 50b) in pressure as hydrate masses form,agglomerate, and break, prior to final blockage. With paraffins the pressure buildup ismore gradual, as deposition on the periphery of the pipe wall causes a gradual increasein line pressure drop. Pressure changes immediately before the blockage should bestudied in addition to such things as fluid slugging, gas/oil ratio, water cut, reservoirpressure, and choke setting, all of which can affect the flow and pressure drop.
When blockages occur in wells it may be difficult to distinguish the cause.Frequently only heating or mechanical means are available to detect the plug source.In flowlines and in wells, solid blockages of scale, rust, sand, etc. are less readilydetected and removed than hydrates or paraffins, so treatment for the more solid plugsshould be considered as when hydrate and wax treatments fail.
In this section on detection of hydrate blockages, Section III.B.1 considersearly warning signs of hydrates, and Section III.B.2 considers methods to determinethe center and length of the plug. A significant amount of material in this section wasobtained from DeepStar IIA Report A212-1, Paraffin and Hydrate Detection Systems,by Paragon Engineering and Southwest Research Institute (SwRI) (April 1996).Another major resource was the Statoil Hydrate Research/Remediation group, whocontributed through in-depth interviews (July 13-15, 1997); this group has more fieldexperience in hydrate remediation than any other at present, perhaps by an order ofmagnitude.
63
III.B.1. Early Warning Signs for Hydrates.
Unfortunately no indicator gives a single best warning of hydrate formation.Frequently the pressure drop in a line, commonly thought to provide the best warning,is wholly inadequate for reasons given in Section III.B.1.a. Instead a suite ofindicators should be used to provide the best early warning before blockages occur.
Of the three portions of the offshore process where hydrates form blockages,early indicators of well formation are least developed. Hydrates in a well are mostoften announced by abrupt flow blockages, accompanied by a high pressure drop. Innormal operation however, the well temperature is high enough to prevent hydrateformation. It is only during abnormal operations such as start-up, shut-in, testing,beginning gas lift, etc. that hydrate formation becomes a problem. When hydratesform without warning in a well, the engineer turns to Section III.C, “Techniques toRemove Hydrate Blockages.”
Early warning methods in the subsea pipeline (Section III.B.1.a) and platform(Section III.B.1.b) are discussed independently below. However, even with themethods listed in this section, there is a significant need for better hydrate detection.
III.B.1.a Early Warnings in Subsea Pipelines. There are four methods forwarnings of hydrate formation in a subsea pipeline: (1) pigging returns, (2) changes influid rates and compositions at the platform separator, (3) pressure drop increases, and(4) acoustic detection. Each method is discussed in the following paragraphs.
(1) Pigging Returns. Periodically a flexible plastic ball or cylinder called a“pig” is pressure driven through pipelines to clear them of condensed matter. Thepig’s trip is initiated via a “pig launcher” and ended by a “pig catcher or receiver”, withthe debris swept from the pipeline into a “pig trap”. A detailed DeepStar II CTR 640-1, Pipeline/Flowline Pigging Strategies, by H.O. Mohr Research and Engineering, Inc.(August 1994) provides a tutorial of this technology.
Frequently hydrate particles are found in pig traps before hydrate blockagesoccur in pipelines, providing notice of the need for corrective action, e.g. increasedmethanol injection. For example hydrate particles may occur when they have beensuspended in an oil or condensate with a natural surfactant, such as the Norsk Hydrooil shown in Figure 34 and accompanying discussion in Section II.G.2.a. Statoil’sGullfaks subsea installation may have undergone several start-ups with hydratepresent, but without problems (Urdahl, 1997) before a blockage in January 1996.
Rule-of-Thumb 17. A lack of hydrate blockages does not indicate a lack ofhydrates. Frequently hydrates form but flow (e.g. in an oil with a naturalsurfactant present) and can be detected in pigging returns.
64
Pigging returns should be carefully examined for evidence of hydrate particles.Hydrate masses are stable even at atmospheric pressure in a pig receiver or catcherdischarge. The endothermic process of hydrate dissociation causes released water toform an ice shell, which provides a protective coating to inhibit rapid dissociation(Gudmundsson and Borrehaug, 1996).
However, it may be very expensive to provide pigging, either via a mobilepigging vessel over the well or from the well head without round-trip piggingcapability. Such costs make examinations of pigging returns an infrequent luxury.
(2) Changes in Fluid Rates or Composition at Platform Separator. Whenthe water production rate is small it may be possible to monitor the rate of waterproduction as an indication of hydrate formation. If the water arrival decreasesappreciably at the separator, hydrates may be forming in the line._____________________________________________________________________Case Study 9. Separator Water Rate as an Indicator of Hydrate Production.
In a controlled experiment, British Petroleum formed hydrates in a 14.5 inchI.D., 13.7 mile long gas line in the southern North Sea. Corrigan et al. (1996)reported that prior to the trial water arrived at the separator in the amount of 1.3bbl/MMscf. The test was started at the time marked “Day 1” in Figure 51. Aftermethanol injection was stopped, the separator water arrival stopped completely afterabout 30 hours (no increase in water volume), while gas flow rates remained steadyand pressure drop did not change.
The first significant increase in line pressure drop (to 2.4 bar in Figure 52) wasobserved 46 hours after the start of the test. A further rise in ∆P to 3.3 bar was notedafter 3 days. Seventy-four hours after the start of the trial, large fluctuations in the gasflow rate were observed that were concurrent with further increases in ∆P. A largeslug of liquid, presumed hydrates, arrived at the slug catcher at the trial conclusion.BP estimated 50 metric tons of hydrate were formed before methanol injection wasresumed._____________________________________________________________________
The above case study is evidence that separator water rate provides an earlyindication of hydrate formation in a gas line with almost no oil/condensate and littlewater production. When water production is substantially higher, it may be difficult tomonitor changes in separator water arrival for an early warning (Todd, 1997; Austvik,1997).
Statoil’s Gjertsen (1997) suggested that changes in gas composition provide anearly indication of hydrate formation. In a rich gas field in the Norwegian sector of theNorth Sea, chromatograms showed a removal of hydrogen sulfide (H2S) from sourgases as hydrates form. Hydrates particularly denude H2S from natural gases, due to
Figure 51 - Water Production for Wet Gas Line(From Corrigan et al, 1996)
0
50
100
150
200
250
300
0 1 2 3 4 5 6 7 8Time (days)
Vo
lum
e (b
arre
ls)
in s
lug
catc
her
ves
sel
Sphere Arrived
Water processed from slug catcher
Water arrival @ 0.6bbls/mmscf
Water processed
Hydrate slug entering slug catcher
Water arriving as slugs - watersimultaneously being processed
from slug catcher
Start of Trial
High DP MeOH Injected
Figure 52 - Differential Pressure Due to Hydrate Blockage(From Corrigan et al, 1996)
10
20
30
40
50
60
70
0 1 2 3 4 5 6 7 8
Time (days)
Dif
fere
nti
al P
ress
ure
(p
si)
Normal line DP at a flow rate of
9 mmscf/d
High DP due to hydrates.
MeOH Injected.
High DP maintained while hydrate melts,
slug flow.
65
the near-optimal fit of H2S in the small hydrate cavities (see Sloan, 1998, Chapter 5).The same statement is not true about the other acid gas, carbon dioxide.
(3) Pressure Drop Increases. Pressure drop (∆P) will increase and flow ratewill decrease if the pipe diameter is decreased by hydrate formation at the wall in a gasline. Since ∆P in pipes is proportion to the square of turbulent flow rates, the changein ∆P is more sensitive than the change in flow. With hydrates however, a largerestriction may be necessary over a long length before a substantial pressure dropoccurs. For example, if a hydrate decreased the effective pipe diameter from 12 to 10inches over a 1000 foot section, the ∆P would only increase 0.05 psi with 10 MMscf/d of gas operating at 1000 psia and 39oF. In addition, the ∆P trace usually containssubstantial noise, making it difficult to observe trends.
Statoil’s Austvik (1997) suggested that, while a gradual pressure increase inhydrate formation will occur for gas systems, a gradual pressure increase is not typicalfor a gas and oil/condensate system. In gas and oil/condensate systems, Statoil’sexperience is that, without advance warning the line pressure drop will show sharpspikes just before blockages occur. Figure 52 shows the BP field experiment(Corrigan et al., 1996) with methanol stoppage in a North Sea gas pipeline with littlecondensate or free water; in that figure step changes and spikes in ∆P are moreprevalent than a gradual increase.
In contrast, recent DeepStar Wyoming trials (Hatton et al., 1997) show bothgradual and spiked pressure drops, in a gas-condensate field. In Case Studies C.25,26, and 27 the pressure built gradually upstream of a plug, while pressure spikesdownstream indicated hydrate sloughing from the wall, with agglomeration andbridging downstream.
However, the DeepStar tests had five pressure sensors spaced at intervals of afew thousand feet. As indicated in the calculation two paragraphs earlier, with onlytwo pressure sensors at either end of a line, severe hydrate wall buildup must occur inorder to sense a significant pressure drop, due to the dampening effect of the gas.Most pipelines are likely to experience hydrates as sudden, extreme pressure drops.
(4) Acoustic Sensing Along Subsea Pipeline. DeepStar IIA Report A212-1,Paraffin and Hydrate Detection Systems, by Paragon Engineering and SwRI indicates:
“The only hydrate crystal detection instrumentation suitable for subsea useidentified by this survey is sand monitoring instrumentation...In a limited numberof laboratory tests, the Fluenta acoustic sand monitor has detected hydrates.However, a detailed study using the Fluenta monitor has not been conducted.”
A typical acoustic sensor from Fluenta is shown in Figure 53. Over 280 unitshave been installed to detect sand impingement on pipe by clamping the unit onto theflow line downstream of a 90o elbow or 45o bend. At flow rates as low as 3 ft/sec the
Figure 53 - SAM 400s Pwtide Detector (From Deepstar IIA A212-1, 1995)
Underwater Mateable
Electronic Connection Stainless Steel Pad
Cable Length - TBO
66
unit can detect 50 micron sand particles. Such units are rated for water depths of4000 ft. and may be diver-assisted or ROV installed with an underwater cable.
Acoustic sensors quantify the “hail on a tin roof” sound typical of hydrateparticles impinging on a wall at a pipeline bend. However, this unit has yet to be fieldtested in a subsea application. The initial background note of the Paragon Engineeringand SwRI (April 1996) study presets a caution which still exists:
“This survey did not identify any proven hydrate or paraffin depositionmeasurement instrumentation for subsea multiphase flow lines or any othertype of fluid transmission lines. For gas transmission lines, ultrasonicinstrumentation has worked in specific applications and for single-phase liquidor gas lines, an acoustical/pigging system has been proposed.”
III.B.1.b Early Warnings Topside on Platforms. In addition to the above fourtypes of subsea early warning systems, two methods are suitable for detection ofhydrates on a platform, where piping and equipment are more available: (5)thermocamera, and (6) gamma-ray densitometer with temperature sensing.
(5) Thermocamera. A thermocamera is a hand-held device which measuresthe infrared spectral transmission as an indicator of system temperature. Since waterabsorbs infrared transmission, the thermocamera is typically used topsides on aplatform with air between the detector and the suspected hydrate plug.
Statoil’s hydrate group provided a thermocamera picture of a hydrate plug, justbeyond a short radius bend in a topside riser, as shown in Figure 54. The originalcolor picture provided better temperature discrimination than the black and whitereproduction presented here. While this blockage is obviously not an “early warning,”the picture is indicative of the instrument’s ability.
As hydrate deposits build and as restrictions cause gas expansion, the lowtemperatures enable portable thermometers to be used in detecting plugs and potentialplug points topside. A thermocamera enables determination of temperature variationsin the system, particularly at points where hydrates might form but a thermocouple istypically not provided, such as downstream of a valve.
The thermocamera is very sensitive to pipe coating, variations in wallthickness, pipe roughness, etc. After location of low temperatures the engineer candetermine whether the system is in the hydrate formation region, to consider correctiveactions such as insulation, heat tracing, inhibitor injection etc.
(6) Gamma-ray Densitometer with Temperature Sensing. A gamma-raydensitometer uses an emitter and sensor on opposite, external pipe walls. Thetransmission of gamma-rays to the sensor is a function of the density of the pipe
Figure 54 - Thermocamera Picture of Hydrates in Horizontal Portion of Riser Topside
(From Austvik, Statoil)
67
contents. This technology is over 50 years old, and is commonly used in the chemicalindustry for level control in high pressure, non-visual systems.
Because densities of hydrates and water are very similar gamma-raydensitometry alone cannot discriminate between the two; at best gamma-raymeasurements indicate changes in conditions which could be hydrates. In combinationwith the temperature downstream of the densitometer (such as at the platform start-upheater as shown in Figure 55) hydrate formation can be discriminated.
Hydrates are indicated by a low temperature in addition to an increase indensity, whereas the water temperature is similar to that of gas. A high density andlow temperature mass in the pipeline is likely to be hydrates, whereas a slug of highdensity but without a temperature drop is probably water. As shown in the blockageremoval Section III.C, even small pressure reductions cause hydrate dissociation,which results in heat being removed from the condensed phases and lowertemperatures. The temperature sensing requirement makes it difficult to use thedensitometer subsea, due to high hydrate plug velocities damaging thermowells.
III.B.2. Detection of Hydrates Blockage Locations.
The two objectives of locating the plug are: (1) to determine the distance fromthe platform from a safety perspective, and (2) to determine the plug length.
In this section three DeepStar reports [(1) A208-1 Methods to Clear BlockedFlowlines, by Mentor Subsea (12/95), (2) A212-1 Paraffin and Hydrate DetectionSystems, by Paragon Engineering and SwRI (4/96), and (3) Hydrate PlugDecomposition Test Program by SwRI (Hatton et al., 10/97)] were supplemented byTommeliten field experiments by Statoil.
Unfortunately there is no precise way to locate the blockage, so the methodsinvolve both art and science. The efficiency of hydrate blockage location schemes isgoverned by the topology of the system and by the hydrate porosity shown in Figures49a,b and Rule-of-Thumb 16, with accompanying discussion.
The early warning methods of Section III.B.1 should be first considered to seeif they apply. Additional methods to determine hydrate blockage locations are:
a) Filling the line/well with an inhibitor or mechanical/optical device,b) Pressure location techniques: reductions, increases, fluctuations, andc) Measuring internal pressure through external sensors.
A recommended composite blockage location method is given in III.B.2.d.
Figure 55 - Platform Use of Gamma Densitometer
GammaDensitometer
Gas
Fro
m P
ipel
ine
Start-upHeater
Thermocouple
PlatformChoke
1st StageSeparator
To Comp./Dehydration
Platform
68
III.B.2.a. Filling the Line/Well with an Inhibitor or Mechanical/Optical Device.When hydrates block a flowline, it is common to fill the line with an inhibitor,particularly when the blockage is close to the platform. The blockage and the linetopology may prevent the inhibitor flow from reaching a blockage far from a platform.
There is some disagreement about whether methanol or glycol should belubricated into the line, and both are used. Since the density of methanol is low, thehigher density glycol (and sometimes brine) is preferred.
The inhibitor injection volume enables the determination of blockage locationrelative to the platform, given the line size and a knowledge of liquid retention withinthe pipeline. In each of the following case studies, the operator was fortunate to reachthe hydrate plug with an inhibitor. In most cases this method is ineffective.____________________________________________________________________Case Study 10. Methanol Lubrication into an Export Line. Texaco reported arestriction in a 12.75 inch gas export line from a platform at Garden Banks Block 189in 725 ft. of water. The export gas was insufficiently dehydrated and water condensedat a low point in the line, where hydrates rapidly formed.
The hydrate blockage was removed by venting from the platform and injectingmethanol down the riser. Hydrates completely melted after a total of twenty to thirty55 gallon drums of methanol were used._____________________________________________________________________
Rule-of-Thumb 18: Attempts to “blow the plug out of the line” by increasingthe pressure differential will result in more hydrate formation and perhaps linerupture due to overpressure. When a hydrate blockage is experienced, for safetyreasons, inhibitor is usually injected into the line from the platform in anattempt to determine the plug distance from the platform.
Such a volumetric determination assumes the plug to be impermeable to theinhibitor and that the liquid hold-up in the line is known (or negligible). Both may beincorrect since hydrate accumulations push substantial liquids ahead of the plug.
____________________________________________________________________Case Study 11. Monoethylene Glycol Lubrication into Well Tubing. An operatorexperienced a blockage in a multi-phase flow stream in the Gulf of Mexico, extendinginside tubing inside a deepwater riser connection between the platform and theseafloor, from two hundred feet below, to several hundred feet above the seafloor.
The well was being cleaned in preparation for production. The well contained4-5wt% CaCl2 completion brine. After hydrocarbon flowed from the well for a fewhours, the well had to be shut-in for two days due to bad weather, but methanol wasnot injected prior to shut-in. A gas hydrate plug formed which held a differentialpressure of 1000 psi without movement.
69
A coiled tubing (see Section III.C.4) was run down the tubing string andethylene glycol was jetted to remove the blockage. Jetting operations took two days,and the entire remedial operation took one week to complete.____________________________________________________________________
For hydrates in a well, Statoil has used a broach similar to that shown in Figure56, lowered on a wireline to determine the blockage depth. A similar wireline heatingtool has been used by Statoil for hydrate dissociation in wells; in this case, the hydrateblockage can be located and dissociated with the same tool. Heating a hydrateblockage is not recommended, unless the end is determined, for safety reasons shownin Figure 2b and accompanying discussion. However, when the hydrate end isdiscernable, heating from one side of the blockage may be a viable option.
In a flowline a wireline, reach rod, coiled tubing, or fiber optics may be used tolocate a plug. However, this detection method is currently limited to the first 10,000ft. from the platform and requires mechanical intervention in the flowline.
III.B.2.b. Pressure Location Techniques: There are three pressure techniquesto locate a hydrate blockage which are performed on the platform side of the plug: (1)pressure reduction, (2) back-pressurization, and (3) pressure fluctuations. Eachtechnique has advantages and disadvantages.
Pressure Reduction. This simple technique takes advantage of hydrateporosity by decreasing the downstream pressure and monitoring the rate of pressurerecovery and the rate of pressure decrease of the upstream side of the plug. Figure 57shows an flowline obstruction one-third the way between the platform and the well. Ifthe pressure is suddenly decreased downstream, the rate of downstream pressurerecovery should be one-half the rate of upstream pressure decrease. With low porosityplugs patience may be required, as illustrated in the following case study.
____________________________________________________________________Case Study 12. Depressurizing the Blockage for Location. In January 1996 Statoilexperienced a hydrate blockage in a black oil system in a 6 inch I.D., 1 mile-long linein the Gullfaks field. The normal oil rate was 18,000 ft3/d, the water rate was 16,242ft3/d, and the GOR was 100-360 scf3/scf3.
The normal line operating pressure was 2420 psia and the hydrate equilibriumpressure (at the low temperature) was 261 psia. With the well shut in, the downstreampressure at the platform was rapidly reduced to 1670 psia. Figure 58 shows blockageupstream and downstream pressure response (note expanded scale). Over a 25 hourperiod, the upstream pressure decreased about 73 psi while the downstream pressureincreased the same amount. It was concluded that the plug was located mid-way inthe pipe. See Case Study 15 (Section III.C.1.d.) for the removal of this Statoil plug.
Figure 56 - Wireline Broach to Dete Hydrate Location in Well
(From S tatoil)
,rmine
Figure 57 - Hydrate Location In a Pipeline
Upstream Downstream
PlugDistance L
2/3 L 1/3 L
Figure 58 - Pressure Change Used to Estimate Plug Location(From Gjertsen et al, 1997)
2300
2320
2340
2360
2380
2400
2420
0 5 10 15 20 25
Time (hours)
Su
bse
a P
ress
ure
(p
sig
)
1660
1670
1680
1690
1700
1710
1720
1730
1740
1750
1760
To
psi
de
Pre
ssu
re (
psi
g)
Subsea Pressure
Topside Pressure
70
Two points should be emphasized about this case study: (1) safety and (2) rate.First, the small diagnostic pressure reduction was made from one side of the plug, wellabove the hydrate dissociation pressure, to prevent safety problems associated with aplug projectile (Section I) propelled by a high differential pressure.
Second, pressure recovery was very slow, averaging about 3psig/hr. This slowrate may not be noticed if pressure is not carefully monitored by platform personnel,who may be inclined to discount a slow changes. The slow rate of pressure changewas thought to be due to the fact that most of the line contained liquid, causing theapparent plug porosity to be about 1000 times smaller than that for gas flow.____________________________________________________________________
Statoil, the company with the most methodical, documented experience inhydrate remediation, prefers the above method of plug location. The method locatesthe blockage center and the relative volumes upstream and downstream of theblockage(s). The disadvantage of the method is that it does not give any idea of thelength of the blockage, how close the blockage is to the platform (due to the unknownplug porosity), or how multiple plugs may affect this location determination. Statoillocates the plug-platform proximity by inhibitor back-injection (see Rule-of-Thumb18) or by back-pressurization, as shown in the following method.
Pressure Increase. To locate a complete pipeline blockage one method is tomeasure the pressure increase as metered amounts of gas are injected at the platform.The rate of pressure increase is correlated to the rate of gas input to determine thelength for a given diameter line between the platform injection point and the blockage.
____________________________________________________________________Example 13. Back-Pressurization to Determine Plug Location. An offshore 16 inchID gas pipeline is in full production when a hydrate plug occurs, blocking flow for a0.6 gravity gas. The line is shut-in and the pipeline cools to the ambient temperatureof 39.2oF. Before hydrate dissociation can begin to take place, the approximatelocation of the plug end should be obtained to determine the best remediation methodand evaluate safety concerns.
One standard location procedure is back-pressurization. This method consistsof pumping a known amount of gas into the pipeline and measuring the change inpressure over time. From these pressure values, an estimate of volume can beobtained through PV=ZnRT.
The following assumptions are made for the problem:1. no porosity of the plug,2. no liquid in the pipeline,3. none of the injected gas condenses,4. constant temperature throughout the pipeline,
71
5. the heat of gas compression is dissipated rapidly, and6. the pipeline is initially at atmospheric pressure.
A reciprocating pump on the platform is used to inject gas at a rate of 4.89lbmole/min into the pipeline, so that the pipeline pressure slowly increases. The heatof compression is assumed to be dissipated in the ocean and the entire temperatureremains at 39.2oF.
The time required for the pipeline to attain even increments of pressure (e.g.400, 600, 850 psia, etc.) are measured and these data can be used to estimate thepipeline volume downstream of the plug via the equation:
PV ZnRT VZnRT
P= → =
whereZ = gas compressibility as a function of P,T, and gas composition. Values
obtained through an equation-of-state or from gas gravity compressibilitycharts (Figures 23-7,8,9 of the GPSA Engineering Handbook (1994))
n = value obtained from data (data table below)P = corresponding pressure for n (data table below)R = 10.73 (Universal Gas Constant in units of psia, oR, lbmol, ft3)T = 498.87oR (seafloor temperature)
Five data points are averaged to estimate the volume of the pipeline betweenthe hydrate plug and the platform. The first data point calculation is as follows:
A line pressure of 400 psia is attained after 60.76 minutes when 297 lbmoles ofgas have been pumped into the line. The gas compressibility is estimated at 0.915from Figures 23-7,8,9 of the GPSA Engineering Handbook (1994). The pipelinevolume is estimated as:
( )( )( )( )( )
33637400
9.49873.10297915.ft
P
ZnRTV =→=
The first estimate of the pipe volume down stream of the plug is 3637ft3.
Estimated Pipeline Volumes Between Platform and PlugData Point # Time (Minutes) Pressure
(psia)Est Volume
(ft 3)1 60.76 400 36372 96.58 600 36643 144.39 850 36674 198.61 1100 36625 300.01 1500 3663
Avg Volume (Platform to Plug 3658
72
This same calculation is summarized for four other data points, in the abovetable. The average approximation for the volume after the hydrate plug was 3658ft3.The cross-sectional area of the pipeline is calculated, in order to estimate the pipelinelength between the plug and the platform. The pipeline cross-sectional area is
22
22
22
396.1144
106.201
4
16
4ft
in
ftin
DA =
=== ππ
Since the pipeline volume = (length)(cross-sectional area), the estimatedlocation of the plug is 2620 feet (= 3658ft3/1.396ft2) away from the platform.____________________________________________________________________
Back-pressurization has been implemented many times in the field and isprobably the method of choice of many operators. However, there are severaldisadvantages which cause significant inaccuracies, as follows:
1. Because hydrate plugs are frequently porous (>50%) and permeable, they transmitflow and act as a “leak” in a system considered to be a closed (i.e. no permeability)
2. The gas compressibility must be well-known in order to determine the pressure andvolume rate increases.
3. The liquid hold-up in the line must be known. This is particularly a disadvantagewhen significant elevation changes result in unknown liquid holdup profiles, orwhen the hydrate plug has accumulated liquid in front of it.
4. The location of multiple plugs cannot be addressed by this method; only the pluglocated nearest the point of injection can be determined.
Due to the above inaccuracies, the method of back-pressurization should besupplemented by other methods, as listed in the Section III.B.2.d.
Pressure Variation. Pressure pulse travel time and pressure frequencyresponse methods to locate a hydrate blockage are discussed in DeepStar IIA ReportsA208-1 and A212-1. Both methods involve measurement of sound wave travel timeor frequency changes from the platform to the blockage. However these analyses havenot been successful to date due to two factors:1. acoustic response is a function of the relative amounts of gas and liquid, which are
usually unknown and may occupy portions of a pipeline.2. reflected pulses are dampened by walls, valves, bends, and by a flexible plug.
III.B.2.c Measuring Internal Pressure through External Sensors. A techniquerecently developed is to measure hoop strain of the pipe as a function of line pressureto determine the location and type of blockage. An ROV places a metal caliper clampon 25% of the pipe circumference using magnets, as shown in Figure 59a. The
Strain vs. Pipeline Length
0
1
2
3
4
5
6
7
8
1 1.5 2 2.5 3 3.5 4 4.5
Relative Distance (km)
Str
ain
/Pre
ssu
re(b
ar)
Clear ClearVisco - ElasticVisco-Elastic
Hard Hard
Figure 59 - Hydrate Plug Detection through Strain Measurement
(From Deepstar A208-1, 1995)
Hydrate detection device which measures the amount of straina pipeline undergoes under high pressure. A graph of strain
vs. pipeline length is shown below. Hydrates are present where verylittle strain occurs in the pipeline.
59a)
59b)
73
platform end of the flowline is pressurized inducing a hoop strain, sensed by thepipeline caliper. The internal pressure causes a hoop strain that results in an outwardmovement of the caliper which varies with the wall deposits of the pipe. Lack of hoopstrain across a section of pipe would indicate a blockage. The signal is transmitted toa work boat at the surface.
This method was successfully used in the North Sea on an 8-inch, 15 km longflow line. Results of the strain gage are shown in Figure 59b for 20 points at variouslengths along a line blocked with paraffin. Points 13, 14, and 15 are shown to beblocked with hard plugs, between visco-elastic plugs (points 15-18 and 3-13) at eitherend. The map in Figure 59b was in agreement with the contents of the flow line whenit was replaced. Recovery and deployment of each measurement required 1-2 hours.Due to necessity for ROV deployment, this method yet to be used to locate a hydrate.
III.B.2.d. Recommended Procedure to Locate a Hydrate Plug. There is no oneprecise method to locate the hydrate plug, so a combination of the above methods areindicated below for best results.
1. Estimate the hydrate formation temperature and pressure of the blockage relative tothe conditions of the pipeline. Use a simulation to determine at what length thecontents of the pipeline enter the hydrate formation envelope during normaloperations. Confirm the simulation with a linear interpolation between the wellheadand platform temperature and pressure. This will provide an approximation of theplug initiation point, but with flow blockage the entire pipeline will cool into thehydrate stability region. This calculation should be done during initial line design.
2. Depressurize the platform end of the plug to about 2/3 of the pressure between thenormal operating pressure and the hydrate formation pressure. Do not decrease thepressure on one side of the plug below the hydrate formation pressure. Monitor therate of pressure increase at the platform and the pressure decrease at the wellhead forthe lesser of (a) either 24 hours or (b) until a significant pressure change (e.g. 75 psig)is obtained at each point. Use the rate of pressure change at wellhead and platform todetermine the center point of plug(s), or relative volumes at each end of the plug(s).
3. Fill the riser with inhibitor to attempt to determine the distance between theplatform and the plug. This may be inaccurate due to pipeline elevation changes, etc.
4. Back-pressure the pipeline and monitor the pressure increase for a measured volumeof gas input. Estimate the distance from platform to plug by the rate of pressurechange, relative to gas input, for a given compressibility and simulated liquid retentionvolume. Use this technique with method 2 to determine volume before the plug.
5. With available resources, use a mechanical device to determine plug location.
74
III.C. Techniques to Remove a Hydrate Blockage.
Four techniques to remove a hydrate blockage are listed in order of frequency:
1. hydraulic methods such as depressurization (Section III.C.1),2. chemical methods such as injection of methanol or glycol (Section III.C.2),3. thermal methods which involve direct heating (Section III.C.3), and4. mechanical methods with coiled tubing, drilling, etc. (Section III.C.4).
Applications of the above methods can be further divided into three cases: (a)partial blockage, (b) total blockage without substantial liquid head, and (c) totalblockage with a liquid head. The following discussions concern only the final twocases. It is assumed that any indication of a partial blockage will be promptly treatedwith massive doses of methanol, the most effective inhibitor. Combinations of theabove methods are simultaneously tried.
Rule of Thumb 19. Regardless of the method(s) used to dissociate the hydrates,the time required for hydrate dissociation is usually days, weeks, or months.After a deliberate dissociation action is taken, both confidence and patience arerequired to observe the result over a long period of time.
Often it is suggested that corrective actions be changed almost hourly whenimmediate results are not observed. Rapidly changing corrective actions, results in“thrashing” without significant effects on plug removal. The “waiting” aspect of plugremoval is frequently the most difficult for platform operating and engineeringpersonnel, who are accustomed to producing results on a continuous basis. Typicaltimes of days or weeks are required for plug removal as indicated by Appendix C casestudies. Measurements such as pressure drop across the plug are continuouslymonitored and changed deliberately, only after some time has passed to gain assuranceof initial method failure.
Rule of Thumb 20. When dissociating a hydrate plug, it should always beassumed that multiple plugs exist both from a safety and a technical standpoint.While one plug may cause the initial flow blockage, a shut-in will cause theentire line to rapidly cool into the hydrate region, and low lying points of wateraccumulation will rapidly convert to hydrate at the water-gas interfaces.
III.C.1. Depressurization of Hydrate Plugs.
This section shows that, from both a safety and technical standpoint, thepreferred method to dissociate hydrate plugs is to depressurize from both sides.Depressurization is particularly difficult when the deepwater liquid head on the hydrate
75
plug is greater than the dissociation pressure. Before that point is addressed, aconceptual picture of hydrate provides some key points in the dissociation process.
III.C.1.a Conceptual Picture of Hydrate Depressurization. When ahydrate plug occurs in an ocean pipeline, the pressure-temperature conditions areillustrated in Figure 60. To the left of the three phase (LW-H-V or I-LW-V) lineshydrates or ice can form, while to the right only fluids can exist. Because the lowestocean temperature (39oF) is well above the ice point of 32oF, ice formation (whichcould block flows) is not a normal operating concern. When hydrates form, flow isblocked so that the plug temperature rapidly decreases to the ocean floor temperatureof 39oF at the pipeline pressure. Figure 60 shows the pressure-temperature conditionsof a pipeline hydrate plug at point A in the two-phase (H-V) region, in which liquidwater has converted to hydrate.
Pressure reduction is accompanied by a temperature decrease at the hydrateinterface. If the pipeline is rapidly depressured without heat transfer, Joule-Thomson(isenthalpic) cooling (line AB) at the hydrate may worsen the problem. If the pressureis reduced extremely slowly, isothermal depressurization (line AC) results. Usually anintermediate pressure reduction rate causes the hydrate interface temperature to besignificantly less than 39oF, causing heat influx from the ocean to melt the hydrate atthe pipe boundary.
With rapid or extreme pressure reduction, the hydrate equilibrium temperaturewill decrease far below 32oF, for example to -110oF for a methane hydrate depressuredto atmospheric pressure. In this case water from dissociated hydrate will rapidlyconvert to ice below the solid-liquid line (I-LW-H shown in Figure 60). If iceformation occurs with hydrate dissociation, then the question arises, “How will the iceplug dissociation rate compare to the hydrate dissociation rate in an ocean pipeline?”
In 1994-1997 field studies, over 20 hydrate plugs were intentionally formedand removed from a 6 inch North Sea line in the Tommeliten Gamma field. In bothlaboratory and field studies these plugs were found to be very porous (>50%) andpermeable. Porous, permeable hydrates easily transmit gas pressure while still actingto prevent free flow in the pipeline. When the pressure was decreased at both ends ofa highly porous hydrate plug, the pressure decreased throughout the entire plug to analmost constant value. The dissociation temperature at the hydrate front is determinedby the pipeline pressure. The depressurization results in a uniform hydrate dissociationtemperature which is in equilibrium with the LW-H-V line pressure in Figure 60,predicted by the methods of Section II.C and II.D.
Pipeline depressurization reduces the hydrate temperature below thetemperature of the ocean floor (39oF for depths greater than 3000 ft.). Heat flowsradially into the pipe, causing dissociation first at the pipe wall as shown in Figure 61.Radial hydrate dissociation controls plug removal, because the pipe diameter (less than
Figure 60 - Isethalpic and Isothermal Plug Dissociation(From Kelkar et al, 1997)
Temperature
Pre
ssur
e
I-L
w-H
I-H-VI-
Lw
-V
Lw-H-V
A
B
C
0=∆H
0=∆T
ICENO HYDRATES
HYDRATES
Figure 61 - Radial Dissociation of Hydrate Plug
B) Pipeline Longitudinal View
A) Pipeline Cross Section
Heat
Water
Heat Heat
76
2 ft.) is typically at least an order of magnitude less than the length of a hydrate plug(frequently more than 50 ft.) in a pipeline.
The radial dissociation concept presents a contrast to previous longitudinaldissociation concepts of non-porous hydrates, in which depressurization from bothends was supposed to result in dissociation progressing from the plug ends toward themiddle (Yousif, et al., 1990; DeepStar Report CTR IIA A208-1, 1995). Asdiagrammed in Figure 62 when the temperature of the hydrate is lower than that of theocean floor, heat flows radially into the system, causing dissociation along the entirelength. Of course some plug dissociation occurs at the ends, but due to much smallerdimensions the radial dissociation (which occurs simultaneously along the plug length)controls blockage removal.
Figure 62 shows a cross section of a pipeline hydrate plug that has beendepressured to provide an equilibrium temperature just above 32oF. Such a pressurecorresponds to about 450 psia for a pure methane gas, but much lower for a naturalgas, as predicted by the methods of Sections II.C. and II.D. Figure 62a shows aninner hydrate core enclosed in a water layer, which results from hydrate melting. Thewater layer is adjacent to the pipe wall. Figure 62b shows the temperature profilefrom the ocean temperature of 39oF at the pipe wall, to the hydrate dissociationtemperature (set by the line pressure to a point just above the ice point) where itremains uniform throughout the hydrate layer. As a result, the radial disappearance ofthe two-phase water+hydrate boundary (X1) determines the disappearance of the finalsolid and eliminate the flow obstruction.
Because hydrate plug detachment occurs first at the pipe wall, a partially-dissociated plug will move down the pipeline when the line is re-started, only to resultin a later plug at a pipeline bend, depression, or other obstruction. The secondblockage by the plug can be more compact than the first, for example if there issubstantial momentum on impact at the bend. This phenomena relates to Rule-of-Thumb 19, indicating that one of the most important aspects of plug removal ispatience to allow time for total dissociation.
In the above conceptual picture, it is assumed that the pipeline is exposed toturbulent, deep ocean water so that the pipe wall temperature is constant at 39oF. If aline is insulated, hydrate dissociation becomes much more difficult because theinsulation which prevented heat loss from the pipe in normal operation will preventheat influx to the pipe for hydrate dissociation. Alternatively, if the pipe is buried inthe ocean floor, the pipe wall temperature will be greater than 39oF, but only by anaverage of about 1oF per 100 ft. of buried depth.
The cross section in Figure 63a shows a hydrate plug dissociation when thepressure is too low. An inner hydrate core is surrounded by an ice layer, that isenclosed in a water layer adjacent to the pipe wall. Figure 63b shows the temperatureprofile from 39oF at the pipe wall, to 32oF at the water-ice interface, to a lower hydrate
Figure 62 - Hvdrate Dissociation with Water Present _
Water Hydrate Water
To= 40°F - T, = 33°F - To=
Wall x? 4 ‘5 Wall
40°F
Moving Boundary
v-v~*Fi- x 1
Moving Boundaries
T,= 40°F
77
dissociation temperature (set by the line pressure) at the ice-hydrate interface, where itremains uniform throughout the hydrate layer. As a result, there are two two-phaseboundaries: a slowly dissociating water-ice boundary (X1), and a second, rapidlydissociating ice-hydrate boundary (X2). We are particularly interested in the rate ofprogress of X1, which determines the disappearance of the final solid (ice), since anysolid phase constitutes a flow obstruction in a pipeline.
Hydrate dissociation to a low pressure almost always results in an ice problemwhich may be more difficult to remove than the initial hydrate. Hydrate removal isaccomplished by both depressurization and heat influx from the surroundings, while anice plug removal must rely on heat influx alone. As a result an ice plug may dissociatemore slowly than a hydrate plug.
For example, if a 16 inch line containing only methane is depressured toatmospheric pressure, 85 days are required for radial dissociation of an ice plug, whileonly 17 days would be required for dissociation of a hydrate plug to water if thepressure was maintained at 450 psig. These calculated results are based upon theradial dissociation model of Kelkar, et al. (1997) in which radial dissociation prevails.
Austvik (1997) noted some exceptions to radial dissociation, particularly forplugs of low porosity/permeability or for very long plugs. Plug permeability maydecrease considerably during the first hours after plug formation; this suggests thatplugs should be dissociated as soon as possible to take advantage of higher porosity.
III.C.1.b Hydrate Depressurization from Both Sides of Plug. There aretwo reasons for the preferred method of two-sided hydrate plug dissociation:
1. For a single plug, dissociation from both sides eliminates the safety concern ofhaving a projectile in the pipeline.
2. Two-sided dissociation eliminates the Joule-Thomson cooling which may stabilizethe downstream side of the plug. With radial dissociation along the plug, two-sided dissociation is more than twice as fast as single-sided dissociation.
For the above reasons, a hydrate plug should be dissociated through a secondproduction line, if available. If this is impossible, depressurization through a serviceline for injecting inhibitors at the well head; in this case provision should be made forremoving or bypassing the check valve in the service line at the well head. In somecases, as in Case Study 14, it may be worthwhile to connect a floating productionvessel to the manifold or wellhead for depressurizing the upstream side of the plug.
_____________________________________________________________________Case Study 13. Gulf of Mexico Plug Removal in Gas Export Line. A hydrateblockage in the export line from Shell’s Bullwinkle platform in the Green CanyonBlock 65 to the Boxe platform was reported in DeepStar Report A208-1 (Mentor
78
Subsea, 1995, page 52). The 12 inch, 39,000 ft. line was un-insulated line. Seawatertemperature was 50oF at the base of the platform in 1400 ft. of water. Gas gravity was0.7, without condensate. Flow rate was 140 MMscf/d at an inlet pressure of 800 psi.
Gas hydrates formed during a re-start after the platform was shut down due toa hurricane. During the shut-in period the gas dehydrator was partially filled withwater. After production was restarted, since the dehydrator was not cleaned outproperly, it was not dehydrating gas as designed, and wet gas entered the export riser,causing water condensation and hydrate formation. A complete hydrate blockageformed in less than one hour, just past the base of the export riser at a low spot.
To remove the blockage, the line was depressured on both sides of the plug.Then methanol was circulated into the line to accelerate the hydrate dissociation rate.After complete removal of the hydrates, the dehydrator was cleaned, inspected and re-started properly. The entire remedial operation required 36 hours to complete. Themajor cost was the lost production time._____________________________________________________________________
When depressurization cannot be easily achieved from both sides of a plug,then more costly steps may be required to balance the depressurization to ensureplatform safety, as indicated in the following case study.
_____________________________________________________________________Case Study 14: Removal of North Sea Hydrate Plug by Depressuring Both Sides.
This case study is a remediation summary of hydrate blockage in an ARCO 16inch, 22 mile long pipeline between a North Sea gas field well and platform.
Plug FormationSetting
The gas field is located in the southern North Sea and consists of three subseawells, flowing into a subsea manifold with a capacity of four well inputs. A graphicalrepresentation of the field is shown in Figure 64. The well’s gas compositions,temperature, and pressure promote hydrate formation, consequently mono-ethyleneglycol (MEG) is injected into the manifold and wellheads to thermodynamically inhibithydrates. The inhibited water, gas, and condensate is then pumped through a 22 mile,trenched, insulated export pipeline to a processing platform where water is removedfrom the condensate. The MEG in the pipeline is recycled and piped back to themanifold via a 3 inch pipeline piggybacked to the export line.
BlockageOn April 14th, 1996 an unusually large liquid slug over-ran the platform
primary separator causing a temporary shut down. The liquid slug was remediated,but complete blockage of the pipeline had occurred during shut-down. It washypothesized that the blockage was a result of a hydrate plug. The reasons were:
Well
Well
Well
ManifoldManifold
Fourth Intake
Host Platform
36 km - 16” Export Pipeline
Figure 64 - Offshore Platform and Manifold(From Lynch, 1996)
79
• The pipeline free water, recovered during depressurization at the platform, did notcontain MEG inhibitor. The 3 inch MEG inhibitor line had ruptured.
• Through back-pressurization, the blockage was found to be 150 meters away fromthe platform. At this location, the pipeline was exited the mudline allowingcontents to be rapidly cooled by ocean currents, causing hydrate formation.
• Slight decreases in pressure determined that the blockage had some porosity. Thishad also been observed for several Statoil hydrate plugs (see Tommeliten FieldCase Studies C.15, C.16, and C.17 in Appendix C. In contrast however, twoDeepStar field trials C.26, and C.27 formed low-porosity, low-permeability plugswhich would transmit pressure very slowly and withstand high pressure drops.)
• The liquid slug which shut down the compressors probably was caused by a partialhydrate plug pushing a fluid front down the pipeline as it moved.
The blockage’s proximity to the platform posed serious safety concerns.Pipeline depressurization was necessary to dissociate the hydrate; however it had to bedone on both sides of the hydrate plug. If only the blockage’s platform side wasdepressured, the pressure differential would cause a projectile to form which coulddestroy the riser piping and damage the platform. The projectile would be life-threatening to workers on the platform and result in costly damages to the platformitself. Consequently, depressurization had to be done through both the platform andthe subsea manifold to ensure safety. Projectiles could form due to dissociation, if gasbecame trapped within multiple plugs. Slow depressurization was required to removepressure build-ups in the hydrate plug(s). Several methods were considered.
Depressurization MethodInitial Ideas
Three questions were raised to determine a proper depressurization method.1. Will the remediation process effectively depressurize the pipeline?2. What is the cost of equipment and modifications?3. How much time is needed to complete the remediation?
Based on these questions, process engineers, consultants, safety management,and diving specialists proposed three potential depressurization methods. They were:
1) Jack-up Rig.Method: Tow a jack-up rig to the site. From the rig, attach a high pressureriser to the manifold’s subsea tree and flare exiting gas via the rig’s flare stack.Modification: A spool piece would have to replace a non-return valve on themanifold’s fourth well intake.Time Required: A drilling rig was not currently available, consequently a delayof approximately eight weeks was needed to locate a suitable rig. The timerequired for hydrate removal could be twelve weeks.Estimated Cost: $1,980,000
80
Feasibility: The large amount of time required to locate a jack up rig made thisan ineffective remediation method, useful in the absence of other methods.
2) MEG Injection LineMethod: Connect the subsea manifold’s spare fourth flange to the 3inch MEGpipeline and flare gas at the platform.Modification: Subsea work would require a spool piece installed between thetwo pipelines. Secondly, a method of injecting methanol was needed toprevent future hydrate growth. The platform (while in operation) requiredsignificant modification to connect the MEG pipeline to its flare stack. Tofurther complicate the matter, all of the MEG currently in the pipeline wouldneed to be stored on the platform, which had limited storage space.Time Required: Six to eight weeks.Estimated Cost: Unknown, expected to be higher than the other methodsbased on the large amount of modifications that were required.Feasibility: Substantial modifications to the platform made this remediationmethod costly and impractical. It was deemed unusable in any circumstance.
3) Floating Production and Storage Vessel (FPSO)Method: Connect a FPSO with a processing plant and flare to the subseamanifold’s fourth flow loop and process the exiting gas. The connectionbetween the manifold and FPSO would be made through a high-pressure,flexible riser.Modification: The platform required no modifications. A diving rig wasrequired to do the subsea work. A valve skid containing both emergency shut-down valves (ESDV’s) and a MEG injection valve was also needed. Theflexible riser and the manifold would be connected with a spool piece. Figure65 is a schematic of the design.Time Frame: A FPSO was available for immediate use, consequently therequired time was expected to be 6-8 weeks.Estimated Cost: $1,906,000.Feasibility: This method proved to be the most feasible. The immediateavailability of a FPSO and diving rig allowed modifications to begin. It wasestimated that the FPSO could be at the site and begin within two weeks.
Establishing Procedures/PermitsIt took approximately two weeks to develop potential remediation processes.
Procedures were then written to firmly establish the processes required for the pipelinedepressurization. Procedures considered the safety, process, and coordinationrequirements between the diving rig and the FPSO. All parties were educated aboutthe tasks involved.
Government permits were applied for at the Health and Safety ExecutivePipeline Inspectorate (HSE) and the Department of Trade and Industry Oil and GasOffice (DTI) for additional gas flaring and well modification. The permits were
FPSOFPSO
Collar Buoy
5 TonClumpWeight
ManifoldManifold
280 meterHigh Pressure
Riser 16” ExportPipe
FPSO process and flaresexiting gas from the manifold
Valve Sled
Figure 65 - Preliminary Remediation Set-up(From Lynch, 1996)
81
expedited by local agencies to prevent delay in hydrate removal. Two weeks wererequired to prepare procedures and permits for depressurization. In the meantime, theFPSO and diving rig were being equipped for the operation and moving to the field.
Depressurization of the PipelineOperations
The divers first task was to manually locate the subsea manifold’s fourth intakeand to isolate it from any trees or flow loops. The fourth well intake was thenmodified with a spool piece for connection with the high-pressure riser. The valveskid was now ready to be put in place. Due to the sandy ocean bottom, it becamenecessary to provide a foundation for the valve skid. The valve skid was placed on aconcrete mattress and then stabilized with gravel bag supports coupled with Tirfors,chain blocks, and ground anchors. This insured that no movement would transferfrom the flexible riser to the valve skid. The valve skid contained ESDV’s and a MEGinjection system for the pipeline. Figure 66 is a figure of the subsea valves and theirattachment to the manifold.
The diving rig then inspected the flexible riser route to ensure that is was clearof debris. It proceeded to deploy 920 ft. of the high pressure riser via a tugger riggedwith a dead man’s anchor. The MEG in the riser provided some buoyancy,consequently the line was anchored through concrete mattresses. A five ton clumpweight was placed at the bottom of the riser with a buoyancy collar attached to thesurface.
The FPSO could only process gas at 600 psig, consequently it required somemodification to process the 1300 psig pipeline gas. Additionally, a quick-release valve(QVD) was needed to enable the FPSO to escape from the riser in case of anemergency. This complicated the design because current quick-release valves couldnot withstand pressures of 1300 psig. Initial design placed choke valves in the riser toreduce pressure for the quick-release valve, however this caused control problems andwas deemed impractical.
An innovative new quick-release valve was developed with a standard valveweak link with three additional hydraulic jacks for manual release. This valve couldwithstand 1500 psig of pressure, allowing choke valves to be placed on the ship’s deckwhich simplified control issues. This design enabled a safe, simplified, control of gaspressures from the deck of the FPSO. A description of the system is shown in Figure67.
The buoyancy of the riser prohibited pipeline intake through the FPSO’smoonpool. Spool pieces were used to allow riser intake from the side of the shipdeck. The riser was also steam traced with 1000 ft. of 1 inch piping to maintain theminimum process temperature required by the FPSO.
Existing 1500 PSI Flange
Manifold MEG
Injection LineESD Valves
6” Manuli Riser
Valve Sled
Figure 66 - Valve Sled with Manifold Interface(From Lynch, 1994)
Initial Design Final Design
Choke Valves
Low PressureQuick-Release
Valve
High PressureQuick-Release
Valve
Choke Valves
Figure 67 - Design with High Pressure Quick-Release Valve(From Lynch, 1996)
The High Pressure QR Valve allowedchoke valves to be placed on the deckof the FPSO. This design easiedpipeline control tremendously.
FPSO FPSO
82
Figure 68 is a complete picture of the FPSO attachment to the subseamanifold. All valves and risers were tested and shown to be in working order. Overallthe modification and installment procedures required one week before pipelinedepressurization could begin.
Determining the Pipeline Minimum Pressure
Reducing pipeline pressure too much could result in ice formation. This causessignificant problems because ice melting might have required significantly more time,than hydrate dissociation. Ice formation was prevented through use of the hydrateequilibrium curve (Figure 69) for the field.
At constant low pressure, hydrates will continually dissociate, maintaining theequilibrium temperature at that given pressure. As the graph illustrates, theequilibrium pressure at 320F was 200 psig. To prevent ice formation, the pipelinepressure could not drop below 175 psig. Consequently, the FPSO reduced thepipeline pressure to 185 psig to maximize hydrate dissociation without ice formation.
Depressurization
Twenty three days were required to completely dissociate the pipeline hydrate.Heat transfer between the ocean and the pipeline was slow because the line wastrenched and insulated in the sea floor. Dissociation was slightly facilitated byoccasional back-pressuring which drew methanol into the plug. Back-pressuring alsoproved beneficial in determining the location of the plug. Figure 70 shows thepressures in the pipeline throughout the depressurization process. Note the slightpressure increases that occurred during depressurization. These formed as a result ofgas pockets suddenly releasing as the plug was dissociated.
The pressure was monitored for 12 hours after the hydrate was thought to bedissociated. No pressure variation was noticed so the flexible riser was recovered andthe depressurization apparatus dismantled. Throughout the whole operation, noequipment failure occurred and the operation progressed smoothly.
Recommissioning the Pipeline
After the hydrate was dissociated, there remained significant amounts of freewater in the pipeline. The pipeline had to be re-commissioned carefully to preventreformation of hydrates. Above normal amounts of MEG were added to the systembefore pipeline start-up. One gas well was opened and the platform flow high tomaintain low pressure, preventing hydrate formation. The high intake caused a highgas velocity which facilitated rapid water removal. The first 12 hour night shiftreported 7000 ft3 of water received from the separator, the water which would result
FPSO
Manuli Hose
Collar Buoy
ClumpWeight
HoseClamp
ManuelBallValve
SafetyValves
34 km16”
ExportPipeline
Figure 68 - Complete FPSO/Manifold Interface(From Lynch, 1996)
Manifold
Umbilical
Chute/Disconnect
Sea Surface
Strops
Figure 69 - Hydrate Formation Curve(From Lynch, 1996)
0
200
400
600
800
1000
1200
1400
30 35 40 45 50 55 60 65
Temperature (oF)
Pre
ssu
re (
psi
g)
Hydrates
No Hydrates
Figure 70 - Pressure of Manifold and PlatformDuring Hydrate Remediation
(From Lynch, 1996)
0
50
100
150
200
250
300
350
400
450
0 2 4 6 8 10 12 14 16 18 20
Time (days)
Pre
ssu
re (
psi
g)
Platform
Manifold
83
from a 1.25 mile long (non-porous) hydrate plug. The high flow rate of gas wasmaintained until the water contained 40% MEG, ensuring that the line was fullyinhibited. The pressures and intakes were then returned to normal operating levels.
Conclusions
The remediation team removed the hydrate plug efficiently. They achieved amonumental task in a very short period of time, preventing more severe economiclosses. Figure 71 provides a timetable of the remediation process. The procedure andmethodology followed could be applied to many different situations. Communication,clear objectives, and excellent resources helped in removing the hydrate plug.
Despite the efficient remediation effort, the economic impact of the hydrateplug was substantial. The cost of depressurizing the pipeline was almost 3 milliondollars, without counting lost production. On top of this, relations between the buyersand producers were tested, due to lack of production. Fortunately, good initialrelations between the two reduced the impact of the disruption. This case study showsthe potential financial loss that can result from hydrate plugs. Hydrate prevention iskey in preventing significant economic and production losses._____________________________________________________________________
III.C.1.c Hydrate Depressurization from Both Sides of Plugs withSignificant Liquid Heads. Results similar to those of Case Studies 13 and 14 maynot be applicable to very deep ocean plugs. When depressuring a multi-phasedeepwater pipeline the hydrostatic pressure (or head) of the liquid against the face(s)of the plug may be higher than the hydrate dissociation pressure. However, theremoval of fluids from each side of a hydrate plug may be difficult.
To date there is little documented experience for depressuring plugs with liquidheads in deepwater lines. However the situation has been evaluated in light of most ofthe case studies in Appendix C, and recommendations are provided in Example 14.
____________________________________________________________________Example 14. Methods of Fluid Removal in Plugged Deepwater Lines. This exampleabstracts an in-depth study of fluid removal as a preliminary step to depressurizinglines done in DeepStar Report A208-1 by J. Davalath (December 1995).
Figure 72 shows the Lw-H-V equilibrium conditions for the Hercules andJolliett fluid conditions in a 50 mile pipeline in 4000 ft. of water in the Gulf of Mexico.When a blockage occurs, if the gas is not vented, the temperature rapidly decreases to40oF with a pressure between 2000-3000 psia (a subcooling of 30-33oF). After gasventing the pressure is still 1000-1300 psia, a factor of 5-6 times greater than the
TASK NAMEOrwell Pipeline Blocked
Attempts to move plug
Development of Jack-up Rig
Development of FPSODecision Made
Development of Detailed Design
HAZOP/Safety Study
FPSO-Manifold Interface Fab.
FPSO Modifications
Subsea Installation
FPSO Transit
FPSO-Manifold Hookup
Depressurization of Line
Pipeline Unblocked
MEG Injection w/ production
APRIL JUNEMAY01 08 15 22 29 06 13 20 27 03 10 17
4/14/96
6/2/96
6/6/96Full Production Resumed
Dissociation of Plug
Figure 71 - Schedule for Complete Plug Remediation(From Lynch, 1996)
Figure 72 - Hydrate Formation Conditions(From Deepstar A-208-1, 1995)
0
500
1000
1500
2000
2500
3000
3500
20 30 40 50 60 70 80
Temperature (oF)
Pre
ssu
re (
psi
a)
Hercules
JollietCool DownConditions BeforeVenting Gasat Platform
Shut-In Conditions After Venting Gas
HYDRATES
NO HYDRATES
Required Pressure to Dissociate Hydrate Plug
84
equilibrium pressure (200 psia) at the ocean floor temperature (40oF) with asubcooling of 22oF.
To initiate hydrate dissociation, the hydrostatic head must be removed below200 psia, to about 150 psia where the equilibrium temperature is 25oF, slightly insidethe ice formation region, so that a 15oF temperature gradient will cause heat to flowfrom the ocean to the hydrate.
In a worst-case scenario, the entire volume from the platform to the manifoldmust be removed. Assuming only 70% of the pipeline volume is filled with liquid, thevolume to be removed would be 12,000 bbls in an 8 inch line and 26,000 bbls in a 12inch line 50 miles long. The techniques listed in Table 8 were considered for liquidhead removal.
All of the options in Table 8 require that the plug location be determined andthat the pipeline have access points in order to remove the pressurizing liquid andplug. If there are no access points, the line will have to be hot-tapped. The figures inthe example indicate that workover vessels need to be positioned above the plug.
Of the seven options summarized in Table 8, those with gas lift were eliminateddue to low liquid removal rates. None of the depressurization options wererecommended; however, multiple access ports at 4 mile intervals were recommendedwith use of coiled tubing as described in Section III.C.4 on mechanical removal.
Table 8. Techniques to Remove Liquid Head Above a Hydrate Plug
Option for Removing Liquids Issues/Limitations
1. Multiphase Pumping to Surface (Figure73) at a rate of 5000 BOPD to remove
liquids in 3-6 days
temporary deployment; electricalsubmersible pump; handle large liquid
volume on workover vessel2. Subsea separator; vent gas &
pump liquid to surfacedeploy separator/pump hardware subsea
3. Gas lift pipes on each side of plug(Figure 74)
extremely slow: 21 days to remove 12,000bbl from 8” line; 25+ days to remove 26,000
bbl from 12 inch line4. Multi-phase pumping with gas lift similar issues to Option 1
5. Combine subsea separator with gas lift too slow; similar issues to Option 26. Displace with nitrogen from platform requires large volumes of N2 at high P7. Launch a gel or foam pig followed by
nitrogengel pigs separate gas and liquid; access
point must be large enough to introduce pig
Ft.
RCiV
Fiaure 73 - Pipeline Depressurization Methods -Multiphase Pump Option (From Deepstar A-208-1, 1995)
Hydrate PLug
1
F ure 74 - r (From Deepstar A208-1,' 1995)
4000 Ft.
85
An alternative to pumping the fluids to the surface is to discharge the fluidsinto a parallel, unblocked flowline. This method would require access points along thepipeline to locate the plug and remove the liquids to the parallel pipeline._____________________________________________________________________
III.C.1.d. Depressurizing One Side of Plug(s). Rule of Thumb 20 indicatesthat multiple hydrate plugs should be assumed to exist in a shut-in line. With multipleplugs, substantial gas may be trapped between the plugs, and depressurizationtechniques should be similar to depressurization through one side of a plug. The over-riding safety concern is that a plug might dislodge from the pipe wall to become aprojectile which can rupture a line or vessel.
Table 9 gives a procedure for depressurizing one side of a hydrate plug. Asimilar procedure can be used with multiple hydrate plugs when liquid heads exist oneach side of the plug. DeepStar A208-1 presents Figure 75 to illustrate the situationto remove two hydrate plugs without an intermediate access point. In this case, it isassumed that there are multiple access points to the pipeline, so that the generalposition of the plug(s) can be located by pressure differential.
The procedure in Table 9 was slightly modified from that proposed by theCanadian Association of Petroleum Producers , in Guideline for Prevention and SafeHandling of Hydrates (1994), and that proposed in DeepStar Report A208-1.
____________________________________________________________________Table 9. Procedure for Depressurization of One Side of a Hydrate Plug, or
Multiple Plugs without an Intermediate Access Port.
When there is only the option to depressurize one side of a hydrate plug, thereare two major concerns for plug removal: (a) that the plug may dislodge and bepropelled in the pipe, becoming a severe safety problem (see Section I) as well asdamaging equipment, and (b) because the plug is porous and permeable, Joule-Thomson cooling of gas flow may cause the downstream end to progress further intothe hydrate stability region.
The following depressurization procedure attempts to address both concerns.While depressurization is most often used for hydrate it is normally preceded byattempts to place inhibitor adjacent to the blockage; this is difficult because flow isrestricted.
1. Depressurize the line by removing the fluids at a slow rate though access ports oneach side of the plugs. If a substantial liquid head is present, the procedure toreduce the pressure could be one of the seven discussed in Example 14.
rl Pump
Fipure 75 - Suggested Procedure to Remove Multiple Hydrate Plums (From Deepstar A-208-1,1995)
r-l Pump
Depressurize at Slow Rate
Hydrate Equilibrium ______________________ _______ _______________________ Pressure
_ _ _ _ _ _ _, ____--; _---; _--__-___--__ Mamtam Pressure Slightly Below Hydrate Equilibrium Pressure
(For Controlled Dissociation
86
2. Before the hydrate dissociation pressure is reached, the pressure should be reducedslightly (e.g. 100 psia), via the access port valves. After each of several pressurereductions wait for the pressure to be equalized across the plug. Plug permeabilityand porosity permits pressure communication to determine gas volumes on eachside. While the hydrate plugs are porous, as indicated in the Statoil Gullfaks case,pressure equalization may be as slow as 3 psi/hour if substantial liquid flowsthrough the plug.
3. Maintaining a low ∆P across hydrate plugs will reduce the threat of a projectile byproviding both a low driving force and a downstream gas cushion (See Example15) for any dislodged plug. In addition a low ∆P across the plug minimizes Joule-Thomson cooling at the plug discharge end.
4. Reduce the pressure in stages to a level slightly below the equilibrium pressure,
pausing for equilibration at each stage. Do not reduce the pressure below thatrequired to reduce the hydrate equilibrium temperature below the ice point. If thepressure is reduced too substantially, an ice plug will result which may be difficultto dissociate.
5. If hydrates are dissociating (but remain in the line) the pressure will slowly rise to a
level equal to the hydrate equilibrium pressure at the ocean bottom temperature. Ifhydrates have dissociated, the line pressure will remain below the hydrateequilibrium pressure.
6. When the plug completely dissociates there will be no ∆P across the section whichhad contained the plug and Section III.D. should be consulted for system start-up.
While the above method represents an ideal depressurization from only oneside, frequently a non-ideal depressurization must be achieved, as in the following casestudy for a plug which had low liquid permeability, with a very low gas to oil ratio. Itshould be noted that liquid permeability through a hydrate plug is about a factor of1000 lower than that of gas. ____________________________________________________________________ Case Study 15. Line Depressured from One Side for Hydrate Plug Removal. InJanuary 1996 Statoil (Gjertsen et al., 1997) depressured a hydrate plug in a North Sealine which was alternatively used as a black oil producer and a gas injector to maintainreservoir pressure. The oil and water production rates were 18,000 ft3/day and 16,242ft3/day respectively, and the gas to oil ratio was usually 100-360 scf/ft3, a fairly lowvalue. The line and plug location method is in Case Study 12 in Section III.B.2.b. Since the plug was about mid-way along the 1.6 mile pipeline, there was not anoption of using an inhibitor because pipeline topology prevented inhibitor contact withthe plug. Since there were no connections at the well the plug had to be depressurized
87
from the platform side only. By considering the hydrate formation curve it wasdetermined that the plug equilibrium pressure was 261 psia but that ice would formwhen the pressure was below 115 psia. Figure 76 shows the depressurization of the line, with the upstream pressure,the platform pressure, and the pressure drop. During dissociation the pressure wasdecreased in steps, and a slow bleed through was observed from 0-73 hours, from 73-90, 95-105 hours, and from 105 through 120 hours. During the time prior to 120 hours, the pressure was above the hydrateequilibrium pressure, and while the upstream pressure decreased steadily, it neverdecreased to the downstream pressure, indicating that the plug was not very permeableto black oil. A second mechanism was that the light oil ends may have been flashing tomaintain a constant pressure upstream. However the increase in downstream pressureoccurred much more rapidly as the downstream pressure was lowered, indicating thatthe plug was porous, even to the black oil. After about 120 hours the line pressure was maintained between 145 -261 psiadownstream of the plug. The plug dissociated about 50-60 hours after thedownstream pressure had been reduced sufficiently for melting by heat influx from theocean. This was indicated by a sudden upstream pressure decrease from 1890 psig to1160 psig, while the downstream pressure increased from 218 psig to 1015 psig duringthe same period. The pressure was decreased to 145 psig and kept there for over 30hours to melt the remainder of the hydrates. Restart of the well (see Case Study 18 Section III.D) was accomplished twoweeks after the original plug developed. This case is another indication of the longtimes required to remediate a hydrate plug. ____________________________________________________________________ Case Studies C.25, C.26, and C.27 in Appendix C are an overview of DeepStarWyoming field studies of hydrate formation and dissociation from one side of the plug.These studies have the best instrumentation of any hydrate studies to date, and provideseveral exceptions to the concepts in this portion of the handbook. For example, intwo of three cases, relatively impermeable plugs were formed, one of which withstooda ∆P of 475 psi and was propelled down the pipeline at a velocity of 270 ft/s. In each DeepStar field trial, depressurization was done gradually in stages fromone side of a hydrate plug with prior testing to ensure that an absorbing gas “cushion”existed downstream. Where the hydrate plug existed upstream of an above-groundbend, angle, or valve, the test was aborted and the plug was depressured from bothsides due to safety reasons. In depressuring one side of a hydrate plug, it is instructive to simulate theworst-case as a dislodged, frictionless, piston projectile in a pipeline, as in Example 15.
Figure 76 - Pressure Change During Depressurization(From Gjertsen et al, 1997)
0
500
1000
1500
2000
2500
3000
0 50 100 150 200 250
Time (hours)
Pre
ssur
e (p
sig)
Subsea Pressure
Topside Pressure
Pressure Difference
88
____________________________________________________________________ Example 15. Simulation of Hydrate Projectile Upon Depressuring One Side of Plug.Xiao and Shoup of Amoco (1996 a,b,c, 1997) performed a series of simulations of ahydrate projectile in preparation for depressurization from one side of a hydrate plugin a Kerr-McGee, Wyoming 4 inch line. The plug was conservatively modeled as africtionless piston.
Using OLGA the steady state flow in the line was modeled prior to blockageformation. The model included pipeline topography to obtain steady state liquidvolumes trapped at low points in the pipeline. The total mass flow was 92 BOPD and4.166 MMscf/d. Figure 77 shows pipeline topography and the liquid holdup. At aground temperature of 34oF, the pipeline was simulated as shut-in for 8 hours,resulting in a simulated plug formation. Hydrate plugs were initially situated at 7,550 ft. from the inlet of a 17,000 ft.pipeline, with upstream pressures of 1150 psig and 575 psig and a constant initialdownstream pressure of 50 psig. Transient velocities of two plugs were simulatedafter formation: (a) a 20 lbm plug which was 5 ft. long, and (b) a 137 lbm plug whichwas 30 ft. long. Velocity profiles were obtained for each plug, propelled by the initialpressure differentials of 1100 psi and 525 psi., against an initial pressure of 50 psigwith a closed valve at the line end.. For an upstream pressures of 1150 psig, the plugs reached a peak velocity 740ft/s (smaller plug) and 450 ft/s (larger plug). For an upstream pressure of 575 psig,the plugs reached a peak velocity of 550 ft/s (smaller plug) and 340 ft/s (larger plug).The inertial effects of the gas caused rapid acceleration and the final position of thelarger plug (700 ft. and 1,700 ft. from the pipe discharge at initial upstream pressuresof 1150 psig and 575 psig respectively) was governed by a pressure balance, caused byexpansion of the upstream gas and compression of the downstream gas. The simulation indicated that liquid condensate present in the line had verylittle effect on the plug maximum velocity when condensate was injected far awayfrom the plug initial position. Figure 78 shows the plug velocity as a function of pipeposition for the case of 1150 psig upstream pressure with a 137 lbm plug. Plugsimulation results were used to plan and execute field plug dissociation tests. Thecalculated plug velocity was an acceptable match with measured plug velocities in thefield with a gamma-ray detector. It should be noted that modeling the plug as a frictionless piston providesconservative results. The modeled plug will be slowed by any friction between plugand the pipe, as well as by blow-by of gas at the wall and through the porous plug. ____________________________________________________________________
Figure 77 - Topography and Steady-State Holdup Profile(From Xiao and Shoup, 1996)
5180
5200
5220
5240
5260
5280
5300
5320
5340
5360
0 2000 4000 6000 8000 10000 12000 14000 16000 18000
Pipeline Distance (ft)
Sta
tio
n E
leva
tio
n (
ft)
0
0.02
0.04
0.06
0.08
0.1
0.12
0.14
Ho
ldu
p
Pipeline
Holdup
500
4%
4Oc
350
8 30a
.s
H 250
3
3 0 200
150
loo
50
0
Figure 78 - Plug Velocity vs. Plug Location (From Xiao and Shoup, 1996)
Upstream pressure=1 150 psig Downstream pressure = 50 psig
137 Ibm plug
10500 11500 12500 13500 14500 15500 16500
Pipeline Distance, ft
89
III.C.2. Chemical Methods of Plug Removal.
When the pipeline is completely blocked, it is difficult to get an inhibitor suchas methanol or ethylene glycol next to the plug without an access port in the plugproximity. While plugs have been proved to be very porous and permeable,particularly in gas systems (see Section III.C.1.a) a substantial gas volume between theplug and injection points (platform or wellhead) hinders contact, particularly when theline cannot be depressured to encourage gas flow through the plug.
Without flow, inhibitors must displace other line fluids through densitydifferences to reach plugs which are close to the platform. Because flowlines havelarge variations in elevation it is unlikely that an inhibitor will reach a plug withoutflow. Nevertheless standard practice is to inject inhibitor from both the platform andthe well side of a plug, in an attempt to get the inhibitor next to a plug. Sometimes theincreased density of heavy brines can provide a driving force to the hydrate plug face.
Methanol or glycol injection is normally attempted first in a line. Densitydifferences act as a driving force to get inhibitor to the face of the plug, causing glycolto be used more than methanol.
The reader is also referred to Section III.B.2.a. “Filling the Line/Well with anInhibitor or Mechanical/Optical Device.”
III.C.3. Thermal Methods of Plug Removal.
When the ends of a hydrate plug cannot be located, heating is very dangerousbecause the pressure rises exponentially with temperature. Both ends of a hydrateplug can seal the high pressure resulting from hydrate dissociation with heating, andthe line can burst as a result. Such a problem is indicated in Case Study 4 of Section I.
Rule of Thumb 21. Because the limits of a hydrate plug cannot be easily locatedin a subsea environment, heating is not recommended for subsea dissociation.
However, heating is a viable option for topside hydrate plugs on a platformwhere a thermocamera can be used to determine the plug limits (and where thepossibility of multiple plugs has been eliminated). Similarly in a plugged well wherethe upper plug end is available, heating may be one of the primary options, as indicatedin the below case studies. Heating a plug in a well can be accomplished using a heatedwireline broach, similar to tool the shown in Figure 56, as discussed on page 68.
_____________________________________________________________________Case Study 16. Plug Dissociation by Heating in a Well. A hydrate plug wasexperienced in a well feeding a jackup platform in the Norwegian sector in mid-May1997. A hydrate plug, initially caused by pressurization of the well with water, formed
90
below the downhole safety valve in the well. This is a particularly precariouscondition which can result in a well blow out, if it is not handled properly.
Field personnel first attempted to decrease the pressure in steps to just abovethe hydrate equilibrium pressure and unsuccessful attempts were made to push MEGthrough the hydrate plug. The next action was to inject MEG into the well leavingonly a small gas volume at the top of the well. With a higher pressure atop the plug,the only way to get gas into the well was by hydrate dissociation via MEG.
When the pressure dropped to 4280 psia, MEG was re-injected into the welluntil the pressure rose to 4930 psia. A total of 0.14 gallons of MEG were re-injected,indicating that a very small amount of hydrates had dissociated. It was concluded theplug had very low permeability and dissociated very slowly. This concluded the periodof “getting to know the plug.”
At that point the pressure was reduced atop the well to 15 psia and shut-in sothat only the additional static head (394 ft. above the plug) maintained pressure abovethe plug. The pressure recovered to 100 psia as an indication that hydrates weredissociating upon pressure reduction. There were at least six similar pressurereduction and recovery confirmations that hydrates were dissociating in the well; eachtime pressure increases exponentially approached an asymptote of 100 psia.
It was determined the keep the pressure at 15 psia on top of the well toprovide constant hydrate melting. The plug temperature was approximately 48oF.Five hours after maintaining the pressure at 15 psia, the hydrate dissociation wascomplete and the pressure atop the well rose to 160 psia. The entire hydrate plugmelted 12 days after the initial formation. Questions remained concerning why theplug did not respond to MEG injection, so that depressurization had to be used._____________________________________________________________________
III.C.4. Mechanical Methods of Plug Removal.
Pigs are not recommended to remove a hydrate plug, because compressionusually compounds a plug problem. Even for partial plugs, hydrate formation at lowlying points of the flowline may cause the pig to become stuck. If a number of hydrateparticles are present in the line, pigging could result in a more severe plug.
Coiled tubing is the final option for hydrate removal. The tubing is put into thepipeline through a lubricator, usually at a platform or floating workover vessel, in aneffort to get an inhibitor such as glycol to the face of the plug.
Coiled tubing is 1/2 to 3-1/2” OD tubing of a maximum length between 15,000and 29,000 ft. (Sas-Jaworsky et al., 1993). The bend radius at the base of the platformriser presents a limit to coiled tubing penetration, with a minimum radius of 6-10 ft.,
91
but a preferred minimum radius of 20 - 60 ft. Penetration distance is a function oftubing size and pipeline diameter as shown in Table 10.
Table 10. Penetration Distance of Coiled Tubing (DeepStar A208, 1995)Tubing Sizeinch
Flowline Sizeinch
Penetrationft.
1.5 4 or 6 3,000 - 5,0001.75 - 2.0 4 or 6 6,000 - 8,000
See Case Study 11 (Section III.B.2.a) for a successful example of hydrate plugremoval with coiled tubing and glycol jetting. In other case histories coiled tubing hasbeen used successfully. For example coiled tubing was recently used to dissociate aplug at Statoil’s Statfjord field (Urdahl, 1997). Coiled tubing is expensive, requiringspecial rigs. The daily cost of coiled tubing in 1997 is $1 million/d to rent the rig.
Coiled tubing technology is being developed. For hydrate applications, threenew types of coiled tubing are listed from the DeepStar A208-1 report by MentorSubsea (Davalath, 1995):1. Coiled tubing can get hydraulic drilling equipment to the plug (Figure 79).2. A tractor can be used to pull the coiled tubing through the flowline from the
platform side (Figure 80) in lines larger than 4 inch ID at a speed of 5400 ft/hr withpenetration distances to 15,000 ft. Testing is underway in Deepstar Project 3202.
3. A promising coiled tubing being developed is composite coiled tubing. The tubingwalls are porous to allow air/gas to lubricate the tubing travel for furtherpenetration. Demonstration has yet to be done.
With the use of coiled tubing it is important to remember that as much as 170 scfof gas evolves from each ft3 of dissociated hydrate. Coiled tubing must have gasflowby capability in the drive mechanism at the tubing front. This will prevent eitherpushing the tubing from the plug face or line over-pressure. For example with the pig-driven coiled tubing shown in Figure 79, gas must be produced from the tubing.
III.D. Avoiding Hydrates on Flowline Shut-in or Start-up
Shut-in and start-up are primary times when hydrates form. On shut-in the linetemperature cools very rapidly to that of the ocean floor (40oF for depth greater than2000 ft.) so that the system is almost always in the hydrate region if the line is notdepressured. At that condition, multiple hydrate plugs can form. For a planned shut-in, two actions are recommended: (a) inject a large amount of inhibitor such asmethanol or ethylene glycol, and (b) depressure the pipeline as soon as possible.
Case Study 11 (Section III.B.2.a) illustrates a hydrate plug formation due to anunexpected shut-in when methanol could not be injected. It is not clear that the line
FiQure 79 - Drillin Head for Solids Removal
(From Deepstar A-208-1, 1995)
/Coiled Tubing Insulation
SLip Actuating Nut
sups, w/ Integrutirlg Seals
Flow Reversing Sub
/Wiper Disks
\\ II’ -Drlll Motet-
Stationary Cutter Blades
Rotating Grater Type Cutting Plate
Flow Nozzles
Figure 80 - Coiled Tubing Tractor (Fluid Driven Version)
(From Deepstar A208-1, 1995)
API Connection
Tractor Section Nornd Force Tractor FOrce
\ Flow for TrKtion Force
92
was depressured immediately after shut-in, but the plug formation was removed viacoiled tubing with glycol jetting. Case Study 17 also illustrates the value of linedepressuring on shut-in.
_____________________________________________________________________Case Study 17. Multiple Plug Formation after Pressurized Shut-in. The followingstudy is from DeepStar Report A208-1 (Mentor Subsea, 1995, page 31). Due to aproblem at a gas plant a 6 inch 600 ANSI flowline was shut-in at 1000 psi, but it wasnot depressured for six days. The normal flow in the pipeline was gas with 2% H2Sand condensate in the amount of 50 bbl/MMscf.
To remove the blockage the wellhead side of the line was depressured byventing over a 15-20 minute period. Then the valve at the header side was vented.During this operation, one of the hydrate plugs partially melted, dislodged from theline and was propelled by the high-pressure gas trapped inside the line. In this casethere were at least two low spots in the line, where sufficient water accumulated toform multiple hydrate plugs. The plug length was estimated to be 33 ft. and the gastrap between the plugs was estimated to be 160 ft. long.
The fast-moving hydrate plug blew a hole through a tee near the header withinhalf a second after the valve was opened at the header. The impact of the plug andassociated debris caused one fatality and one injury to personnel operating the valve.Follow-up investigations and math modeling showed that 230 - 820 ft. of highpressure gas in a 6 inch line would be sufficient to cause the damage that occurred. Insubsequent operations, hydrate plugging was prevented by: (1) injecting methanol orglycol during each start-up, (2) for planned shutdowns, a hydrate inhibitor wasinjected prior to stopping flow followed by depressurization, and (3) for unplannedshutdowns, the pipeline was depressured within the first 24 hours following shut in._____________________________________________________________________
On start-up before reaching steady state, all parts of the system are particularlysusceptible to hydrates, while the system is heating with warm fluids from thereservoir. During this time small hydrate particles which have formed may becompacted by flow (or by pigs) to form a plug. A typical start-up procedure involvesinjecting large amounts of inhibitor and using diesel fuel.
_____________________________________________________________________Case Study 18. Pipeline Start-up after Hydrate Formation. In 1996 a Statoil black oilpipeline plug occurred in the Norwegian sector of the North Sea, as described in CaseStudy 15 (Section III.C.1.d). After several precautions, the pipeline was depressuredfrom one side of the plug, and when the plug had melted the line was maintained atatmospheric pressure for over one day to eliminate the light components which mightform hydrates.
93
Before start-up, methanol was injected in the amount of 530 gallons in the 6inch ID, 1.6 mile line from the platform. The pipeline was then pressurized with dieselfrom the platform to the sub-sea valve, in an amount which indicated that the pipelinewas nearly empty of liquid after the previous depressurization to atmosphericconditions. A further injection of diesel corresponding to two pipeline volumes waspumped into the pipeline and well. Subsequently the well and the pipeline were putinto production without any hydrate problems._____________________________________________________________________
III. E. Recommendations and Future Development Areas
III.E.1. Recommendation Summary for Hydrate Remediation. The lessons ofhydrate plug remediation may be summarized succinctly:
1. Hydrate plugs are always dissociated, but the time scale is usually days to weeks.Deliberate changes and Patience are required. Hourly changes are ineffectual.
2. Multiple hydrate plugs should always be assumed and treated as a safety hazard.3. Many hydrate plugs are porous and transmit pressure easily while acting to
obstruct flow. Some plugs are permeable to gas, but less so to condensate orblack oil. This concept controls many aspects of hydrate dissociation, includingradial depressurization, Joule-Thomson cooling through the plug, and the fact thatdepressurization may cause the plug downstream temperature to decrease belowthe hydrate equilibrium temperature.
4. Methods are not well-defined for locating hydrate plugs and determining theirlength. However, knowledge of the precise location and length of a plug would bea vital help in dissociation.
5. Attempts to “blow the plug out of the line” via a high upstream pressure alwaysresults in a larger, more compacted hydrate.
6. Depressurization from both sides of hydrate plugs is the preferred method ofremoval, from both safety and technical viewpoints. This implies access points atboth plug ends through dual production lines, service lines, etc.
7. If the pressure is decreased too much, the hydrate plug will rapidly form an iceplug which may be more difficult to dissociate.
8. In a deepwater line a liquid head on a hydrate plug may be sufficient to preventdepressurization. Liquid heads removal is a current challenges to flow assurance.
9. In some cases, depressurization from one side of a plug has been safely done.10. Heating is not recommended for hydrate plugs without a means for relieving the
excess gas pressure when hydrates dissociate.11. Coiled tubing represents the primary mechanical means for dissociating hydrates.12. Usually methanol or glycol is injected into plugged flowlines, but this is seldom
effective due to the necessity to get the inhibitor at the face of the plug.13. Inhibitor injection and de-pressuring techniques are available for system shut-in
and start-up - two times of jeopardy in formation of hydrate plugs.
94
III.E.2. Recommendations for Future Work. Recommendations for futurework to aid remediation supplements those from DeepStar Report A208-1 (MentorSubsea, 1995) based upon case studies represented in the body of this report and inAppendix C.
1. Investigate the use of various access points along a flowline to allow (1) locatingthe plug, (2) removal of liquid head at each side of a plug, and (3) depressuringfrom each side of the plug. Such options include (a) multiple access points along apipeline, (b) dual production lines, (c) wellhead access through service lines withcheck valves removed or bypassed, and (d) blind flanges and valves at manifold.
2. Investigate the use of various coiled tubing techniques to enter a long distancesubsea line, such s (a) locomotive-type device for pulling coiled tubing, (b) pigsmounted outside of coiled tubing to assist penetration, (c) composite coiled tubingto reduce drag.
3. Consider using a long radius riser (from 20-80 ft.), eliminating bends and “S”configurations where water might accumulate, and reducing line low spots.
4. Eliminate un-necessary restrictions and valves in the system and provide forheating or methanol injection where Joule-Thomson cooling is a problem.Consider installing a heater on the platform to prevent hydrate formation in thechoke and/or separator.
5. Consider providing pressure and temperature monitors a various points along thepipeline. Provide for hydrate prevention at these instrument points.
6. A mathematical model should be refined and verified to include radial dissociationof a hydrate plug. A proven, predictive model for hydrate dissociation is notcurrently available.
95
IV. Economics
Economics provide the motivation for all engineering action. When we ask,“Why should hydrates be of concern?” the ultimate answer relates to economics. Evenconcerns of higher value (e.g. safety or the environment) relate directly to economicsbecause such concerns can prevent process operations.
The present section is aimed at providing economics in terms of hydrate safety,prevention, and remediation - the previous three major sections of the handbook. Inevery example provided, a time stamp enables the reader to update the economics,using such tools as the Consumer Price Index.
IV.A. The Economics of Hydrate Safety
While insurance actuaries can set a price on life and limb, usually an ethicalconcern for worker well-being dictates safe operation, and companies take well-deserved pride in the number of “accident-free days.” While safety is related to costs,the policy is invariably, “Safety at all costs,” or “If we cannot operate safely, wecannot operate.”
Consideration of the Section I five case studies, plus Case Study 17 in SectionIII.D all imply a direct relationship between safety and cost, because blowout andsevere process damage occurred in all cases. Lysne (1995, p. 7,8) lists three suchincidences in which hydrate projectiles erupted from pipelines at elbows and causedthe loss of three lives and over $7 million in capital costs.
IV.B. The Economics of Hydrate Prevention
The Guidelines for Hydrate Prevention Design (Section II.H) are certain toinvolve economics which relate to individual cases, for example the cost of a heatingsystem installed around a instrument gas control valve. Frequently such costs can beminimized in the original process design, without expensive retrofits to correctdeficiencies. In this section we are concerned with the economics of two principleprevention means: (1) chemical injection and (2) heat management.
IV.B.1. Chemical Injection Economics.
In the United States in 1996 the oil and gas production industry used anestimated 400 million pounds of methanol, the most-used hydrate inhibitor (Houston,1997). Shell’s methanol usage in deepwater is forecast at 50 million pounds per year.With expanding deepwater work the use of methanol is expected to grow 50 - 75%over the next five years. These economics provided the initial motivation toinvestigate hydrate prevention via other means.
96
IV.B.1.a. Economics of Methanol and Mono-ethylene Glycol. One of the mostcomprehensive documented economic studies of methanol injection was provided byDeepStar I CTR 240 by INTEC Engineering (December 1992). In that work chemicalinjection costs (including MeOH) were reported for two Gulf of Mexico cases: (a) theJolliet reservoir which is naturally gas lifted, and (b) the Hercules reservoir has aheavier crude with low GOR (500 scf/b).
The study recommends that there should be one transmission line per chemicaland a subsea distribution system, with the main features:
• one surface pump per chemical on the host platform• one subsea transmission line per chemical• subsea distribution using remotely adjustable, pressure compensated flow
control valves packaged into control pods, and• use of steel or stainless steel subsea chemical transmission lines.
Details of annual hydrate chemical costs for 1-well and 20-well cases, 60 milelines, are provided in Table 11. Table 12 gives capital costs for methanol injectionsystems in 1 well and 20 wells for the Jolliet and Hercules reservoirs. It should benoted however, that both tables are based solely upon methanol only in the free waterphase. As noted in Sections II.D.2 and II.D.3. frequently methanol losses to the vaporand condensate phases are quite important.
The amounts of chemical injection should be based upon the methods ofSection II.D, recalling the relative advantages and disadvantages of each inhibitor. Forexample, methanol is significantly dissolved in the vapor and liquid hydrocarbonphases, not just the free water phase (considered in Table 11).
Methanol had a delivered cost to an offshore Gulf of Mexico platform of $2.00per gallon during the 1996-7 winter. Such costs fluctuate significantly and aresomewhat seasonal; typical dockside North Sea methanol costs were $0.11/lbm
($0.72/gallon) and ethylene glycol cost were $0.27/lbm during the 1997 summer.
Since methanol recovery is not economical, methanol injection is normallyconsidered as an operating cost. The Deepstar Study CTR 221-1 (ParagonEngineering, 1994) shows methanol recovery to be very expensive in Table 3 of CaseStudy 7 in Section II.G.1.a. For methanol recovery late in the life of a field, the totalinstalled cost on an existing platform was estimated at $16.7 million ($20 million totalinstalled cost with a new platform) while the annual operating cost is $6 million. Forethylene glycol (MEG) a low vapor pressure results in a smaller recovery column,making the economics much more favorable.
97
Table 11. Cost of Methanol Usage for Jolliet and Hercules Reservoirsin Gulf of Mexico (from DeepStar I CTR 240)
Rsrvr No.Well
lifeyr
WHPpsia
Oilbbl/D
GasMscf/d
H2Obbl/D
Subcool∆T(oF)
wt%MeOH
MeOHgpm
Costk$/yr
Jolliet 1 1 3,317 2,500 1,670 2 46.3 35.3 0.026 7.65“ “ 5 1,970 600 3,268 17 38.8 33.1 0.206 60.6“ “ 8 911 43 850 4 27.8 27.3 0.040 11.8
Jolliet 20 1 2,821 4,400 2,948 4 43.9 34.8 0.051 15.0“ “ 5 1,449 16,400 33,948 124 34.4 31.1 1.412 415.6“ “ 10 1,123 5,100 36,210 172 30.8 29.2 1.832 539.2
Hercules 1 1 2,325 1,367 869 0 41.2 33.9 0 0“ “ 5 1,737 465 376 666 37.0 32.3 7.889 2,322“ “ 8 1,824 23 30 22 37.7 32.6 0.263 77.4
Hercules 20 1 2,325 2,700 3,000 0 41.2 33.9 0 0“ “ 5 1,064 22,700 12,500 4,540 30.0 28.7 47.75 14,054“ “ 10 1,064 19,100 11,700 5,157 30.0 28.7 54.24 15,964
Table 12. Transmission Lines (60 miles) Sizing, Costs and PumpingSkid Costs (From DeepStar I. CTR 240)
Reservoir No.Wells
Min. LineID (in)
Line CostMM$
Skid Costk$
Jolliet 1 0.306 1.03 5.20Jolliet 20 0.780 1.11 30.00
Hercules 1 1.629 1.79 34.00Hercules 20 2.815 1.79 89.50
Additional cost of valve, actuator, manifolding,and packaging = $6,700/well.
Rule-of-Thumb 22. Methanol loss costs can be substantial when the totalfraction of either the vapor or the oil/condensate phase is very large relative tothe water phase.
Sections II.C. and II.D. provide a quantitative means of validation of the aboveRule-of-Thumb. Example 7 provides a conservative sample calculation in which 15%of the methanol is lost to the vapor and liquid hydrocarbon. Statoil provided thebelow table showing a reduction in condensate price for different methanolconcentrations (>30 ppm by wt) in a condensate.
98
Table 13. Cost Penalties for Methanol in Propane(from Austvik, 1997)
MeOH conc inC3H8 ppm (wt)
Reduction in 1993 Price (comment)
0-30 030-50 0-$2/metric ton (MT = 2205 lbm)50-100 $2-4/MT (or $0.25 - $0.50/ Bbl)100-200 $4-6/MT (excludes some crackers)200-300 $6-9/MT (excludes most crackers)>300 $9-40/MT (reduced confidence in product)
IV.B.1.b. Economics of New Types of Inhibitors. Notz (1994) provided oneof the best comparisons of operating costs for methanol with kinetic inhibitors inTables 14 and 15 for a Texaco field in the North Sea.
Table 14. Relative Usage of Methanol and Kinetic Inhibitor in a North Sea Field(P. Notz, July 26, 1994)
Pipe-line(in)
phase Lifeyrs ofUse
H2Oavg,bbl/d
Time inhydratezone, hr
Max∆T,oF
wt%MeOHin H2O
MeOH1000lbm
KI1000lbm
active
16 multi 0 304 0 no hyd 0 0 0“ “ 7 287 2.3 11.7 16 20.9 0.409“ “ 15 150 40.9 31.4 33 19.3 NA*
8 liquid 0 346 0 no hyd 0 0 0.“ “ 7 295 7.9 17.5 20 21.5 0.441“ “ 15 118 43.2 19.4 21 8.8 0.170
12 gas 0 17 8.4 25.5 28 9.7 0.128“ “ 7 10 24.6 30.8 33 5.9 NA*“ “ 15 4 72.9 32.0 33 2.4 NA*
NA* = conditions too severe for kinetic inhibitor (KI)
99
Table 15. Comparison of Methanol and Kinetic Inhibitor Cost in North Sea(P. Notz, July 26, 1994)
Years When Kinetic Inhibitor isEffective
Over Entire 15 Year Life of Reservoir
Line(in)
phase UseYrs
Methanol KineticInhibitor1
Methanol Replacing MeOH withKI Whenever Possible
MMlbm
$MM MMlbm
$MM MMlbm
$MM KI 1,MMlbm
MeOH2
MM lbm
TotalCost$MM
16 multi 7-9 25.9 7.8 0.36 3.2 72.9 22.1 0.36 50.0 18.48 liquid 6-15 52.5 15.9 1.05 9.3 52.5 15.9 1.05 0 9.312 gas 1-4 15.6 4.7 0.03 0.26 33.0 10.0 0.03 17.4 5.5
1This includes the cost of methanol solvent for the kinetic inhibitor2This is the methanol cost in those years when a KI cannot be used because ∆T > 27oF
Grainger (1997) compared inhibition costs of methanol, glycol, and aThreshold Hydrate Inhibitor (THI) which consisted of kinetic inhibitors, a corrosioninhibitor, and a solvent. Table 16 represents dock delivery costs, without shipping tothe platform.
Table 16. Comparison of Three Types of Inhibitor Costs in the North Sea(M. Grainger, August 21, 1997)
Chemical MEG MeOH THI
Conc/bbl H2O,wt% 15 15 0.25Quantity, lbm 61.7 61.7 0.882Cost/bbl H2O $16-$17 $6.5 - $7.5 $8-$10
From the above table, operating cost benefits appear marginal (better thanMEG, worse than MeOH). Bloys et al. (1995) suggested that economics werefavorable for new developments (due for example, to capital savings of avoidingregeneration systems) but marginal for retrofits of systems with traditional inhibitorssuch as monoethylene glycol.
The incentive for newer kinetic control methods is a substantial capital costreduction by the elimination of the need for offshore platform equipment, and a smalloperating cost reduction. In one high water production North Sea field, BP reckonedthe capital costs savings at $50 million for platform costs including methanol injectioncosts, glycol drying, and regeneration (Argo and Osborne, 1997).
100
For example, BP currently operates some Southern North Sea pipeline wet,thereby saving the capital cost of drying the gas on the platform. In addition to capitalcost, a savings may be realized on the platform itself.
Rule-of-Thumb 23. The cost of a fixed leg North Sea platform is $77,000/ton.
The above Rule-of-Thumb was given by Edwards (1997). BP would like touse unmanned platforms, but the inhibitor recovery units on some platforms preventsdoing so. As additional costs, Edwards also estimated the operation of an inhibitorrecovery unit at 2 hrs/day operator time and maintenance requires 600-700 hr/year at$85/hr.
The economics of anti-agglomerants are much less certain than those statedabove for kinetic inhibitors. No documented costs of anti-agglomerants were found.However, anti-agglomerant economics should include such factors as emulsionbreaking, recovery, and disposal.
IV.B.2. Heat Management Economics.
Of the two heat management techniques (insulation methods and pipelineheating) only the insulation state-of-the-art is established sufficiently for economics tobe available. However, deepwater development is causing the cost of such technologyto change rapidly, and the information contained here should be updated byknowledgeable workers.
IV.B.2.a. Economics of Insulation. The minimum overall coefficientachievable with a non-jacketed system is 0.3 BTU/hr-ft2-oF (from DeepStar ReportIIA CTR A601-a, 1995) and costs are typically $50-$300/ft for pipes with diametersbetween 8 inches and 12 inches.
Rule-of-Thumb 24. In order to achieve a desired heat transfer coefficient of 0.3BTU/hr-ft 2-oF, a non-jacketed system costs $1.5 million per mile. Typical costs ofinsulation via bundled lines are $1.5 -$2.0 million/mile.
Figures 43 and 44 compare the cost of the three above types of insulation forwater depths of 6000 ft over 60 miles at oil production rates of 25,000 and 50,000bbl/d, respectively. If an average U = 0.3 BTU/hr-ft2-oF is required with a flowlinepressure of 4000 psia, bundled flow lines are more cost effective. Technical detailsand associated economics are provided in Section II.G.4.a.
101
IV.C. The Economics of Hydrate Remediation
When hydrate blockages occur, production is shut in. When coupled with thefact that all hydrate-blocked lines and wells have to be re-commissioned, the questionarises about how lost production should be treated - i.e. as lost or as deferred revenue.
There is consensus that shut-in production should be counted as lost revenuefor reasons including the following:
1. Usually deferred production is counted at the end of reservoir life, so that the timevalue of money is considered. A dollar today is worth more than a dollartomorrow due to inflation.
2. Fields are frequently sold over their lifetime, and deferred cost means lost revenueduring the ownership of a field.
3. Contracts specify delivery and penalties for non-delivery of hydrocarbon.
Production losses due to hydrates are site-specific, but are enormous whenconsidered collectively. From the hydrate group with the largest world-wideremediation experience, Austvik of Statoil(1997) indicated the magnitude of theproblem by saying, “At any instant in the North Sea, there is probably a hydrateblockage which requires remediation.” As one onshore example, despite largequantities of methanol injection for hydrate prevention, Todd et al. (1996) report 66hydrate blockages occurred in one well and production line during winter of 1995-1996, resulting in production losses of more than $240,000.
Offshore hydrate remediation techniques are very costly if they are notexplicitly included into the initial design. For example, the ARCO Case Study 14represented a fortunate instance (in April 1996) of having an extra flange available atthe manifold for depressurization. In this case two solutions were technicallyavailable:
1. Jack-up Rig. Tow a jack-up rig to the site and attach a high pressure riser to themanifold’s subsea tree. Flare exiting gas via the rig’s flare stack. The estimatedcost: was $2 million and a delay of approximately eight weeks was needed tolocate a suitable rig. The time required for hydrate removal could be twelveweeks.
2. Floating Production and Storage Vessel (FPSO). Connect a FPSO with aprocessing plant and flare to the subsea manifold’s fourth flow loop. Theestimated cost was $1.9 million and a FPSO was available for immediate use,reducing the required time to 6-8 weeks.
Other techniques such as the use of coiled tubing were not available at thetime. (The daily cost of coiled tubing was $1 million/d to rent the rig in July, 1997.)The final cost of depressurizing the ARCO pipeline was almost 3 million dollars,
102
without production losses. Even with such high costs, the loss of production usuallycauses time to be the deciding resource during remediation.
During remediation periods, gas supply is usually met via substitution.However, the borrowing capacity is typically limited to 5 times the daily capacity, sothat gas supplies are purchased from the spot market. Typical non-delivery penaltycosts are $50,000/day after tax on a gas production unit of 125MM scf/d. Non-delivery contract pressures may be eased by considering hydrates as a “Force Majeure”as done in ARCO Case Study 14, implying that no penalties should be incurredbecause there was no human error.
103
Appendix A.Gas Hydrate Structures, Properties, and How They Form
The following discussion is excerpted from the monograph by Sloan (1998,Chapters 2 and 3), to which the reader may wish to turn for a more completeexplanation. Two recent hydrate conference summaries (Sloan et al., 1994; Monfort1996) also provide research and applied perspectives of the hydrate community.
Gas clathrates are crystalline compounds which occur when water forms acage-like structure around smaller guest molecules. While they are more commonlycalled hydrates, a careful distinction should be made between these non-stoichiometricclathrate hydrates of gas and other stoichiometric hydrate compounds which occur forexample, when water combines with various salts.
Gas hydrates of current interest are composed of water and the following eightmolecules: methane, ethane, propane, isobutane, normal butane, nitrogen, carbondioxide, and hydrogen sulfide. Yet other apolar components between the sizes ofargon (3.5 Å) and ethylcyclohexane (9Å) can form hydrates. Hydrate formation is apossibility where water exists in the vicinity of such molecules at temperatures aboveand below 32oF. Hydrate discovery is credited in 1810 to Sir Humphrey Davy. Dueto their crystalline, non-flowing nature, hydrates first became of interest to thehydrocarbon industry in 1934, the time they first were observed blocking pipelines.Hydrates concentrate hydrocarbons: 1 ft3 of hydrates may contain 180 scf of gas.
Hydrates normally form in one of three repeating crystal structures shown inFigure A.1. Structure I (sI), a body-centered cubic structure forms with small naturalgas molecules found in situ in deep oceans. Structure II (sII), a diamond lattice withina cubic framework, forms when natural gases or oils contain molecules larger thanethane but smaller than pentane. sII represents hydrates which commonly occur inhydrocarbon production and processing conditions, as well as in many cases of gasseeps from faults in ocean environments.
The newest hydrate structure H (sH) named for its hexagonal framework, hascavities large enough to contain molecules the size of common components of naphthaand gasoline. Some initial physical properties, phase equilibrium data, and modelshave been determined for sH and one instance of in situ sH in the Gulf of Mexico hasbeen found. Since information on structure H is in the fledgling stages, and since itmay not occur commonly in natural systems, most of this appendix concerns sI and sII.
A.1. Hydrate Crystal Structures.
Table A.1 provides a hydrate structure summary for the three hydrate unitcrystals (sI, sII, and sH) shown in Figure A.1. The crystals structures are given withreference to the water skeleton, composed of a basic "building block" cavity which hastwelve faces with five sides per face, given the abbreviation 512. By linking thevertices of 512 cavities one obtains sI; linking the faces of 512 cavities results in sII; insH a layer of linked 512 cavities provide connections.
Fimre A-l - Three Hydrate Unit Crystals and Constituent Cavities (From Sloan, 1998)
Structure I Structure IJ
46 Waler Molecules 136 Water Molecules
Structure H
34 Water Molecules
104
Spaces between the 512 cavities are larger cavities which contain twelvepentagonal faces and either two, four, or eight hexagonal faces: (denoted as 51262 in sI,51264 in sII, or 51268 in sH). In addition sH has a cavity with square, pentagonal, andhexagonal faces (435663). Figure A.1 depicts the five cavities of sI, sII, and sH. InFigure A.1 a oxygen atom is located at the vertex of each angle in the cavities; thelines represent hydrogen bonds with which one chemically-bonded hydrogen connectsto an oxygen on a neighbor water molecule.
Table A.1 Geometry of Cages in Three Hydrate Crystal Structures in Figure A.1
Hydrate Crystal Structure I II HCavity Small Large Small Large Small Medium LargeDescription 512 51262 512 51264 512 435663 51268
Number of Cavities/Unit Cell 2 6 16 8 3 2 1Average Cavity Radius, Å 3.95 4.33 3.91 4.73 3.913 4.063 5.713
Variation in Radius1, % 3.4 14.4 5.5 1.73 Not AvailableCoordination Number2 20 24 20 28 20 20 36Number of Waters/Unit Cell 46 136 34
1. Variation in distance of oxygen atoms from center of cage.2. Number of oxygens at the periphery of each cavity.3. Estimates of structure H cavities from geometric models
Inside each cavity resides a maximum of one of the small guest molecules,typified by the eight guests associated with 46 water molecules in sI(2[512]•6[51262]•46H2O), indicating two guests in the 512 and 6 guests in the 51262
cavities of sI. Similar formulas for sII and sH are (16[512]•8[51264]•136H2O) and(3[512]•2[435663]•1[51268]•34H2O) respectively.
Structure I, a body-centered cubic structure, forms with natural gasescontaining molecules smaller than propane; consequently sI hydrates are found in situin deep oceans with biogenic gases containing mostly methane, carbon dioxide, andhydrogen sulfide. Structure II, a diamond lattice within a cubic framework, formswhen natural gases or oils contain molecules larger than ethane; sII represents hydratesfrom most natural gas systems gases. Finally structure H hydrates must have a smalloccupant (like methane, nitrogen, or carbon dioxide) for the 512 and 435663 cages butthe molecules in the 51268 cage can be as large as 0.9 Å (e.g. ethylcyclohexane).Structure H has not been commonly determined in natural gas systems to date.
A.2. Properties Derive from Crystal Structures.
A.2.a. Mechanical Properties of Hydrates. As may be calculated via Table A.1,if all the cages of each structure are filled, all three known hydrates have the amazingproperty of being approximately 85% (mol) water and 15% gas. The fact that thewater content is so high suggests that the mechanical properties of the three hydratestructures should be similar to those of ice. This conclusion is true to a firstapproximation as shown in Table A.2, with the exception of thermal conductivity andthermal expansivity. Many sH mechanical properties of have not been measured.
105
Table A.2 Comparison of Properties of Ice and sI and sII Hydrates
Property Ice Structure I Structure IISpectroscopicCrystallographic Unit Cell Space Group P63/mmc Pm3n Fd3m No. H2O molecules 4 46 136 Lattice Parameters at 273K a =4.52 c =7.36 12.0 17.3Dielectric Constant at 273 K 94 ~58 58Far infrared spectrum Peak at 229 cm-1. Peak at 229 cm-1 with othersH2O Diffusion Correl Time, (µsec) 220 240 25H2O Diffusion Activ. Energy(kJ/m) 58.1 50 50Mechanical PropertyIsothermal Young’s modulusat 268 K (109 Pa)
9.5 8.4est 8.2est
Poisson’s Ratio 0.33 ~0.33 ~0.33Bulk Modulus (272 K) 8.8 5.6 NAShear Modulus (272 K) 3.9 2.4 NAVelocityRatio(Comp/Shear):272K 1.88 1.95 NAThermodynamic PropertyLinear. Therm. Expn: 200K (K-1) 56x10-6 77x10-6 52x10-6
AdiabBulkCompress:273K(10-11Pa) 12 14est 14est
Speed Long Sound:273K(km/sec) 3.8 3.3 3.6TransportThermal Condctivity:263K(W/m-K) 2.23 0.49±.02 0.51±.02
A.2.b. Guest: Cavity Size Ratio: a Basis for Property Understanding. Thehydrate cavity occupied is a function of the size ratio of the guest molecule within thecavity. To a first approximation, the concept of "a ball fitting within a ball" is a key tounderstanding many hydrate properties. Figure A.2 may be used to illustrate fivepoints regarding the guest:cavity size ratio for hydrates formed of a single guestcomponent in sI or sII.1. The sizes of stabilizing guest molecules range between 3.5 and 7.5 Å. Below 3.5Å
molecules will not stabilize sI and above 7.5 Å molecules will not stabilize sII.2. Some molecules are too large to fit the smaller cavities of each structure (e.g. C2H6
fits in the 51262 of sI; or i-C4H10 fits the 51264 of sII).3. Other molecules such as CH4 and N2 are small enough to enter both cavities
(512+51262 in sI or 512+51264 in sII) when hydrate is formed of single components.4. The largest molecules of a gas mixture usually determines the structure formed.
For example, because propane and i-butane are present in many natural gases, theywill cause sII to form. In such cases, methane will distribute in both cavities of sIIand ethane will enter only the 51264 cavity of sII.
5. Molecule sizes which are close to the hatched lines separating cavity sizes exhibitthe most non-stoichiometry, due to their inability to fit securely within the cavity.
Table A.3 shows the size ratio of several common gas molecules within each ofthe four cavities of sI and sII. Note that a size ratio (guest molecule: cavity) ofapproximately 0.9 is necessary for stability of a simple hydrate, given by the
Figure A-2 - Relative Sizes of Hydrate Guest and Host Cavities
(From Sloan, 1998)
106
superscript “F”. When the size ratio exceeds unity, the molecule will not fit within thecavity and the structure will not form. When the ratio is significantly less than 0.9 themolecule cannot lend significant stability to the cavity.
Table A.3 Ratios of Guest: Cavity Diameters for Natural Gas Hydrate Formers
(Molecular Diameter) / (Cavity Diameter)Structure I Structure II
Cavity Type=> 512 51262 512 51264
Molecule Guest Dmtr (Å)
N2 4.1 0.804 0.700 0.817F 0.616F
CH4 4.36 0.855F 0.744F 0.868 0.655H2S 4.58 0.898F 0.782F 0.912 0.687CO2 5.12 1.00 0.834F 1.02 0.769C2H6 5.5 1.08 0.939F 1.10 0.826C3H8 6.28 1.23 1.07 1.25 0.943F
i-C4H10 6.5 1.27 1.11 1.29 0.976 F
n-C4H10 7.1 1.39 1.21 1.41 1.07F indicates the cavity occupied by the simple hydrate former
As seen in Table A.3, ethane as a single gas forms in the 51262 cavity in sI,because ethane is too large for the small 512 cavities in either structure and too small togive much stability to the large 51264 cavity in sII. Similarly propane is too large to fitany cavity except the 51264 cavity in sII, so that gases of pure propane form sIIhydrates from free water. On the other hand, methane's size is sufficient to lendstability to the 512 cavity in either sI or sII, with a preference for sI, because CH4 lendsslightly higher stability to the 51262 cavity in sI than the 51264 cavity in sII.
A.2.c. Phase Equilibrium Properties. In Figure A.3 pressure is plotted againsttemperature with gas composition as a parameter, for methane+propane mixtures.Consider a gas of any given composition (marked 0 through 100% propane) on a linein Figure A.3. At conditions to the right of the line, a gas of that composition willexist in equilibrium with liquid water. As the temperature is reduced (or as thepressure is increased) hydrates form from gas and liquid water at the line, so threephases (liquid water + hydrates + gas) will be in equilibrium. With further reduction oftemperature (or increase in pressure) the fluid phase which is not in excess (water inpipeline environments) will be exhausted, so that to the left of the line the hydrate willexist with the excess phase (gas).
All of the conditions given in Figure A.3 are for temperatures above 32oF andpressures along the lines vary exponentially with temperature. Put explicitly, hydratestability at the three-phase (LW-H-V) condition is always much more sensitive totemperature than to pressure. Figure A.3 also illustrates the dramatic effect of gascomposition on hydrate stability; as any amount of propane is added to methane thestructure changes (sI Æ sII) to a hydrate with much wider stability conditions. Notethat a 50% decrease in pressure is needed to form sII hydrates, when as little as 1%propane is in the gas phase.
Figure A-3 - Three-Phase (Lw-H-V) Equilibria of Methane+Propane Mixtures
(From Sloan, 1998)
of
.-
107
Any discussion of hydrate dissociation would be incomplete without indicatingthat hydrates provide the most industrially useful instance of statisticalthermodynamics prediction of phase equilibria. The van der Waals and Platteeuwmodel which forms the basis for HYDOFF was formulated after the determination ofsI and sII structures shown in Figure A.1. With the model, one may predict the three-phase pressure or temperature of hydrate formation, by knowing the gas composition.For further detailed discussion the reader is referred to Sloan (1998, Chapter 5).
A.2.d. Heat of Dissociation. The heat of dissociation (∆Hd) may be consideredto be the heat (rigorously, enthalpy change) required to dissociate hydrates to a vaporand aqueous liquid, with values given at temperatures just above the ice point. For sIand sII, to a fair engineering approximation (±10%) ∆Hd depends mostly on crystalhydrogen bonds, but also the cavity occupied within a wide range of component sizes.
Enthalpies of dissociation may be determined via the univariant slopes of phaseequilibrium lines (ln P vs. 1/T) in previous paragraphs, using the Clausius-Clapeyronrelation [∆Hd = -zR d(ln P)/d(1/T)]. As one illustration, simple hydrates of C3H8 or i-C4H10 have similar ∆Hd of 55,500 and 57,200 BTU/(lbmol gas) because they bothoccupy 51264 cavities, although their guest:cavity size ratios differ (0.943 and 0.976).
As a second illustration, similar slopes of lines in Figure A.3 show thatmixtures of CH4 + C3H8 have a value of ∆Hd = 34,000 BTU/(lbmol gas) over wideranges of composition, wherein C3H8 occupies most of the 51264 cavities, while CH4occupies a small number of 51264 and many 512. Figure A.4 shows similar line slopes(and thus ∆Hd values) for binary mixtures of methane when the large guest is changedfrom C3H8, to i-C4H10, to n-C4H10. Since natural gases almost always contain suchcomponents, ∆Hd = 34,000 BTU/(lbmol gas) is valid for most natural gas hydrates.
A.3. Formation Kinetics Relate to Hydrate Crystal Structures.
The answer to the questions, "What are hydrates?" and “Under what conditiondo hydrates form?” in the previous sections is much more certain than answers to"How do hydrates form?". We don’t know how hydrates form, but we can makesome educated guesses about kinetics. The mechanism and rate (i.e. the kinetics) ofhydrate formation are controversial topics at the forefront of current research.
The kinetics of hydrate formation are clearly divided into three parts: (a)nucleation of a critical crystal radius, (b) growth of the solid crystal, and (c) thetransport of components to the growing solid-liquid interface. All three kineticcomponents are under study, but an acceptable model for any has yet to be found.
A.3.a. Conceptual Picture of Hydrate Growth. In a conceptual picture, thislaboratory proposed that clusters at the water-gas interface may grow to achieve acritical radius as shown schematically in Figure A.5, by the following steps:
1. When natural gases dissolve in water there is conclusive evidence that watermolecules organize themselves to maximize hydrogen bonding around each apolarmolecule. The resulting liquid clusters resemble the solid hydrate cavities of
Figure A-4 - Three-Phase (Lw-H-V) Equilibria of Methane+ (Propane and Tvo Butanes)
(From Sloan, 1998)
TEMPERATURE (OF) ,27 7 , ,3$, , , 4p , 47 55 67
1
1
0 l -
0 ‘-
TEMPERATURE (1000/K)
Figure A-5 - Schematic Model of Hydrate Cluster Growth (From Sloan, 1998)
+ Gas
A. Initial Condlflon Pressure and temperature in hydrate’ forming region, but no gas molecules dissolved in wafer
6. Labile Clusters ,C. Agglomeration Upon dissolu&n of Labile clusters gas in water. labile agglomerate by sharing. ctusters form faces, thus increasing immediately. disorder.
D. Primary Nuclealion and Growth When the size of cluster agglomerates nacbes a critical value, growth begins.
108
Figure A.1. These fluid clusters are envisioned to join other clusters as thebeginning of the hydrate crystallization process.
2. Figure A.5 indicates an autocatalytic reaction mechanism hypothesized for hydrateformation based upon limited experimental evidence. The figure depicts theprogress of molecular species from water [A], through metastable species [B] and[C], to stable nuclei [D] which can grow to large species.
3. At the beginning of the process (point A), hydrogen-bonded liquid water and gasare present in the system. Water clusters around gas molecules to form both largeand small clusters [B] similar to the hydrate cages of sI and sII. At point [B], thecages are termed “labile” - they are relatively long-lived but unstable.
4. The cages may either dissipate or grow to hydrate unit cells or agglomerations ofunit cells [C], thus forming metastable nuclei. Since these metastable unit cells at[C] are of subcritical size, they may either grow or shrink in a stochastic process.The metastable nuclei are in quasi-equilibrium with the liquid-like cages until thenuclei reach a critical radius. After attaining the critical radius [D], the crystalsgrow rapidly in a period sometimes called catastrophic growth.
5. In our conceptual picture, when the system is heated, it is driven to the left inFigure A.5, and stable hydrate crystals are dissociated. Once the hydratedissociation point is reached and passed, there are still labile microscopic speciesin the water that range in size from multiple hydrate unit cells [C] to metastablenuclei [B]. These residual structures are present up to a certain level of thermalenergy above dissociation. At temperatures below that upper boundary, thesespecies causes a decrease in induction or metastability time of a successive run,because the “building blocks” of crystals remain in the liquid. However, onceabout 100ºF is passed, no residual structure remains to promote hydrate formation.
The above cluster model conceptual picture is most likely to occur at theinterface, either in the liquid or the vapor side. The reader should note that the aboveis a largely unproven hypothesis, whose only justification is to serve as a mentalpicture for qualitative predictions and future corrections.
In contrast to well-determined thermodynamic properties, kineticcharacterization of hydrates is very ill-determined. One has only to turn to the recentreview of hydrate kinetics by Englezos (1995) or to the author’s monograph (1998) todetermine the following unsettling facts which act as a state-of-the-art summary:
• Hydrate nucleation is both heterogeneous and stochastic, and therefore is onlyapproachable by very approximate models. Most hydrate nucleation modelsassume homogeneous nucleation and typically cannot fit more than 80% of thedata generated in the laboratory of the modeller.
• Hydrate growth kinetics are apparatus-dependent; the results from one laboratoryare not transferable to another laboratory or field situation.
• In both kinetics and thermodynamics the hydrate phase is almost never measured.• The hydrate dissociation models derived from solid moving-boundary differential
equations do not account for the porous, surface formation, and occlusion natureof hydrates on a macroscopic scale.
• No satisfactory kinetic model currently exists for formation or dissociation. Due tothe unsatisfactory state of hydrate kinetics knowledge, this area is the subject ofintensive research at the present.
109
Appendix B.User’s Guide for HYDOFF and XPAND Programs
A Word of Caution
While it is hoped that the programs accompanying this book will be of use inestimating the limiting conditions of hydrate formation, the author should not andcannot be held totally accountable for the use of the predictions which the programprovide. If there is a safety consideration or an important process decision to be madebased upon the program’s predictions, the user is cautioned to obtain a second opinionfrom someone knowledgeable in hydrate phase equilibria, before proceeding.
Executive Summary
Program SpecificationsThis program has been developed to run in IBM-PC compatible computers
having DOS as operating system. The program is executable without any additionalhardware or software requirements.
Contents of the DiskThe 3.5 in. disk provided with this handbook contains four files:
1. HYDOFF.EXE, an executable file to prediction hydrate formation conditions,2. FEED.DAT, a file to be used as external input of the feed components and
composition for HYDOFF. FEED.DAT is an optional file; it should be noted thatHYDOFF will run regardless whether the file FEED.DAT is present.
3. XPAND.EXE an executable file to determine the isenthalpic (∆H=0) andisentropic (∆S=0) gas expansion conditions, and
4. HYDCALC.XLS, a shortcut estimation spreadsheet to calculate methanol ormonoethylene glycol amounts. Use of this program is specified in Section II.B.
Appendix B provides common examples using HYDOFF and XPAND whichmay then be modified by the engineer for his/her own purposes. Section B.1 considersthe use of HYDOFF (and FEED.DAT), while Section B.2 details the use ofXPAND.EXE.
B.1. HYDOFF
B.1.a. Running the Program
The program can be executed directly from the 3.5 in disk or copied to thehard-drive and then executed. It is recommended to make a backup copy of the
110
program in case problems occur (e.g. virus). At the DOS prompt, simply typeHYDOFF and follow the instructions given by the program.
B.1.b. Program Overview
The essence of the program is same as the program accompanying themonograph by Sloan (1998), to which the reader is referred for a full explanation. Theprogram has the central purpose of providing information about hydrate phaseequilibria with and without thermodynamic inhibitors. However, the versionaccompanying this handbook has been abbreviated for rapid use. The programprovides pressure predictions of structure I and II hydrates at a given temperaturewith and without thermodynamic inhibitors (methanol, salt (NaCl), or mixturesthereof) at three- and four-phase conditions (I-H-V, LW-H-V, LW-H-V-LHC).
The method used by the program for hydrate phase equilibria is based on thevan der Waals and Platteeuw model, as described by Sloan (1997, Chapter 5) and thehydrocarbon fluid phases are modeled with the Soave-Redlich-Kwong equation ofstate with parameters obtained from experimental measurements.
B.1.c. Specifications for a Problem
Before any calculation is performed by the program, the user is asked to inputsome basic information, such as: units that he/she prefers to operate in, componentspresent in the feed, feed composition, temperature, type and amount ofthermodynamic inhibitor(s).
The feed components and composition can be directly input in the program orspecified in the FEED.DAT file which can be read by the program. It should be notedthat the FEED.DAT file must be present in the same directory as HYDOFF.EXE. Theunits and feed composition can be changed at any point during the execution of theprogram without actually exiting.Note: When specifying components directly in the program (i.e., not using FEED.DATfor feed input) components can be separated by a space or comma or <ENTER (or)RETURN>.
The program has a MAIN MENU that directs the user to the desired type ofcalculation. Once a particular calculation is chosen, the user is asked to enter thetemperature, and if applicable, concentration of thermodynamic inhibitor(s) in the freeaqueous phase.
It should be noted that at no point in the program is the user asked to enter aninitial guess for the calculations (for pressure predictions). The program has its own
111
internal initial guess. Also, the user does not have to specify the equilibrium phases forany calculation. The equilibrium phases are given as output of the predictions.
B.1.d. What to Expect for an Answer
The standard output for hydrate phase equilibria calculations will display:1. Equilibrium phases (I-H-V, LW-H-V or LW-H-V-LHC).2. Equilibrium pressure.3. Hydrate equilibrium crystal structure (sI or sII).4. Phase components and compositions (i.e. feed, fluid hydrocarbon, and hydrate).5. Fractional occupancy of cages by hydrate formers in each type of hydrate cavity.
Different outputs will be shown for each calculation type. Examples to followwill better illustrate how the program is structured and the format of the output.
B.1.e. Some Important Notes
The program is structured to prompt the user whenever incorrect or improperinformation is input. Following is a list of limitations and guidelines of which the usershould be aware.1. The maximum number of components is limited to 17 (seventeen).2. The weight percentage of methanol as inhibitor is limited to 50 wt%.3. The freezing point depression for systems containing both methanol and salt isdetermined by additive contributions of methanol and salt in solution.4. The total amount of methanol is assumed to be in the aqueous phase. Possiblepartitioning of methanol into other phases (condensate or gas) is neglected.
Example 1 - Temperature and Pressure predictions for Hugoton Gas (experimentaldata by Kobayashi, R., et al. (1951))
Gas Composition: Component Mole %
Methane 73.29 Ethane 6.70 Propane 3.90 i-Butane 0.36
n-Butane 0.55 Nitrogen 15.00 n-Pentane 0.20 n-Hexane 0.00
Pressure prediction @ T = 51.35 °F
112
HYDRATE PREDICTION PROGRAM: HYDOFF
(ACCOMPANYING THE OFFSHORE HYDRATE HANDBOOK) Release Date : July 3rd, 1997
COPYRIGHT : Professor E. Dendy Sloan Center for Hydrate Research Department of Chemical and Petroleum-Refining Engineering Colorado School of Mines, Golden, CO 80401
PHONE:(303) 273-3723 FAX:(303) 273-3730
This program has been designed to provide phase equilibria of hydrates in a manner consistent with available experimental data. Your comments and feedback are welcome for future improvement of the program.
Press RETURN to continue ...
AVAILABLE UNITS ARE AS FOLLOWS :
TEMPERATURE PRESSURE (1) Fahrenheit psia (2) Kelvin kPa
Please select the desired set of Units :1
The program has been designed to allow the user to input the feed components and composition directly in the program or through an external file, namely, FEED.DAT
If the user wishes to read the feed components and composition from FEED.DAT, please make sure the information is entered correctly into FEED.DAT (user has to CHANGE the COMPOSITIONS ONLY) and FEED.DAT is in the same directory as the executable HYDOFF.EXE file.
Is the FEED COMPONENTS and COMPOSITION saved under FEED.DAT (No=1 Yes=2)?1
How many COMPONENTS (excluding Water) are present?8
sII HYDRATE FORMERS
1. Methane 2. Ethane 3. Propane 4. i-Butane 5. n-Butane 6. Hydrogen Sulfide 7. Nitrogen 8. Carbon Dioxide
NON-HYDRATE FORMERS
9. n-Pentane 10. i-Pentane 11. Hexane 12. Heptane 13. Octane 14. Nonane 15. Decane 16. Toluene
113
Which Components are present? Please list Hydrate formers first1 2 3 4 5 7 9 11
Enter the MOLE FRACTIONS of each Component :
Mole Fraction of Methane : 0.7329
Mole Fraction of Ethane : 0.0670
Mole Fraction of Propane : 0.0390
Mole Fraction of i-Butane : 0.0036
Mole Fraction of n-Butane : 0.0055
Mole Fraction of Nitrogen : 0.1500
Mole Fraction of Pentane : 0.0020
Mole Fraction of Hexane : 0.0000
THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE
(1) MAIN Program for Equilibrium Hydrate Predictions (2) Display CURRENT Feed Composition (3) Change FEED Composition (4) Change Program UNITS (5) DISCARD all Data and begin NEW Problem (6) Exit HYDOFF Program
1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
1
Enter the required Temperature (in F)51.35
THREE-PHASE (Lw-H-V) EQUILIBRIUM CONDITION
Temperature : 51.35 F Experimental pressure Equilibrium PRESSURE : 399.92 psia 365.1 psia
Press RETURN to Continue . . .
Equilibrium Hydrate : STRUCTURE II
Composition of Phases at Equilibrium
114
FEED VAPOR HYDRATE Methane .7329 .7329 .5777 Ethane .0670 .0670 .0299 Propane .0390 .0390 .3076 i-Butane .0036 .0036 .0408 n-Butane .0055 .0055 .0063 Nitrogen .1500 .1500 .0377 n-Pentane .0020 .0020 .0000 n-Hexane .0000 .0000 .0000
Press RETURN to Continue . . .
Fractional Occupancy of Cages
SMALL LARGE Methane .6916 .0444 Ethane .0000 .0739 Propane .0000 .7602 i-Butane .0000 .1008 n-Butane .0000 .0155 Nitrogen .0461 .0011 n-Pentane .0000 .0000 n-Hexane .0000 .0000
Do you wish to do another calculation at the SAME composition? (No=1 Yes=2)1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
7
THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE
(1) MAIN Program for Equilibrium Hydrate Predictions (2) Display CURRENT Feed Composition (3) Change FEED Composition (4) Change Program UNITS (5) DISCARD all Data and begin NEW Problem (6) Exit HYDOFF Program
6End of run : HYDOFFStop - Program terminated.
115
Example 2 - Pressure prediction with methanol (experimental data by Ng, H.-J., andRobinson, D.B. (1983))
HYDRATE PREDICTION PROGRAM: HYDOFF (ACCOMPANYING THE OFFSHORE HYDRATE HANDBOOK)
Release Date : July 3rd, 1997 COPYRIGHT : Professor E. Dendy Sloan Center for Hydrate Research Department of Chemical and Petroleum-Refining Engineering Colorado School of Mines, Golden, CO 80401
PHONE:(303) 273-3723 FAX:(303) 273-3730
This program has been designed to provide phase equilibria of hydrates in a manner consistent with available experimental data. Your comments and feedback are welcome for future improvement of the program.
Press RETURN to continue ...
AVAILABLE UNITS ARE AS FOLLOWS :
TEMPERATURE PRESSURE (1) Fahrenheit psia (2) Kelvin kPa
Please select the desired set of Units :1
The program has been designed to allow the user to input the feed components and composition directly in the program or through an external file, namely, FEED.DAT
If the user wishes to read the feed components and composition from FEED.DAT, please make sure the information is entered correctly into FEED.DAT (user has to CHANGE the COMPOSITIONS ONLY) and FEED.DAT is in the same directory as the executable HYDOFF.EXE file.
Is the FEED COMPONENTS and COMPOSITION saved under FEED.DAT (No=1 Yes=2)?1
How many COMPONENTS (excluding Water) are present?7
sII HYDRATE FORMERS
1. Methane 2. Ethane 3. Propane 4. i-Butane 5. n-Butane 6. Hydrogen Sulfide 7. Nitrogen 8. Carbon Dioxide
NON-HYDRATE FORMERS
116
9. n-Pentane 10. i-Pentane 11. Hexane 12. Heptane 13. Octane 14. Nonane 15. Decane 16. Toluene
Which Components are present? Please list Hydrate formers first1 2 3 5 7 8 9
Enter the MOLE FRACTIONS of each Component :
Mole Fraction of Methane : 0.7160
Mole Fraction of Ethane : 0.0473
Mole Fraction of Propane : 0.0194
Mole Fraction of n-Butane : 0.0079
Mole Fraction of Nitrogen : 0.0596
Mole Fraction of Carbon Dioxide : 0.1419
Mole Fraction of Pentane : 0.0079
THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE
(1) MAIN Program for Equilibrium Hydrate Predictions (2) Display CURRENT Feed Composition (3) Change FEED Composition (4) Change Program UNITS (5) DISCARD all Data and begin NEW Problem (6) Exit HYDOFF Program
1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
2
Enter the required Temperature (in F)47.03
Enter the WEIGHT PERCENT of Methanol (up to 50wt%)10
FOUR-PHASE (Lw-H-V-Lhc) EQUILIBRIUM CONDITION WITH INHIBITOR(S)
Inhibitor :10.00 wt% Methanol
Temperature : 47.03 F Experimental pressure Equilibrium PRESSURE : 773.01 psia 800.6 psia
117
Press RETURN to Continue . . .
Equilibrium Hydrate : STRUCTURE II
Composition of Phases at Equilibrium
FEED VAPOR LIQUID HYDRATE Methane .7160 .7160 .7159 .6033 Ethane .0473 .0473 .0473 .0405 Propane .0194 .0194 .0194 .2615 n-Butane .0079 .0079 .0079 .0132 Nitrogen .0596 .0596 .0596 .0167 Carbon Dioxide .1419 .1419 .1419 .0647 n-Pentane .0079 .0079 .0079 .0000
Press RETURN to Continue . . .
Fractional Occupancy of Cages
SMALL LARGE Methane .7630 .1036 Ethane .0000 .1094 Propane .0000 .7064 n-Butane .0000 .0358 Nitrogen .0221 .0011 Carbon Dioxide .0679 .0390 n-Pentane .0000 .0000
Do you wish to do another calculation at the SAME composition? (No=1 Yes=2)1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
2
Enter the required Temperature (in F)33.71
Enter the WEIGHT PERCENT of Methanol (up to 50wt%)20
FOUR-PHASE (Lw-H-V-Lhc) EQUILIBRIUM CONDITION WITH INHIBITOR(S)
Inhibitor :20.00 wt% Methanol
Temperature : 33.71 F Experimental pressure Equilibrium PRESSURE : 566.2 psia 691.8 psia
118
Press RETURN to Continue . . .
Equilibrium Hydrate : STRUCTURE II
Composition of Phases at Equilibrium
FEED VAPOR LIQUID HYDRATE Methane .7160 .7159 .7159 .5931 Ethane .0473 .0473 .0473 .0367 Propane .0194 .0194 .0194 .2772 n-Butane .0079 .0079 .0079 .0139 Nitrogen .0596 .0596 .0596 .0150 Carbon Dioxide .1419 .1419 .1419 .0642 n-Pentane .0079 .0079 .0079 .0000
Press RETURN to Continue . . .
Fractional Occupancy of Cages
SMALL LARGE Methane .7618 .0786 Ethane .0000 .0991 Propane .0000 .7487 n-Butane .0000 .0375 Nitrogen .0199 .0007 Carbon Dioxide .0709 .0317 n-Pentane .0000 .0000
Do you wish to do another calculation at the SAME composition? (No=1 Yes=2)1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
7
THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE
(1) MAIN Program for Equilibrium Hydrate Predictions (2) Display CURRENT Feed Composition (3) Change FEED Composition (4) Change Program UNITS (5) DISCARD all Data and begin NEW Problem (6) Exit HYDOFF Program
6End of run : HYDOFFStop - Program terminated.
119
Example 3 - Temperature and Pressure predictions with salt(s) (experimental data byDholabhai, P.D., et al. (1994))
HYDRATE PREDICTION PROGRAM: HYDOFF
(ACCOMPANYING THE OFFSHORE HYDRATE HANDBOOK) Release Date : July 3rd, 1997
COPYRIGHT : Professor E. Dendy Sloan Center for Hydrate Research Department of Chemical and Petroleum-Refining Engineering Colorado School of Mines, Golden, CO 80401
PHONE:(303) 273-3723 FAX:(303) 273-3730
This program has been designed to provide phase equilibria of hydrates in a manner consistent with available experimental data. Your comments and feedback are welcome for future improvement of the program.
Press RETURN to continue ...
AVAILABLE UNITS ARE AS FOLLOWS :
TEMPERATURE PRESSURE (1) Fahrenheit psia (2) Kelvin kPa
Please select the desired set of Units :1
The program has been designed to allow the user to input the feed components and composition directly in the program or through an external file, namely, FEED.DAT
If the user wishes to read the feed components and composition from FEED.DAT, please make sure the information is entered correctly into FEED.DAT (user has to CHANGE the COMPOSITIONS ONLY) and FEED.DAT is in the same directory as the executable HYDOFF.EXE file.
Is the FEED COMPONENTS and COMPOSITION saved under FEED.DAT (No=1 Yes=2)?1
How many COMPONENTS (excluding Water) are present?2
sII HYDRATE FORMERS
1. Methane 2. Ethane 3. Propane 4. i-Butane 5. n-Butane 6. Hydrogen Sulfide 7. Nitrogen 8. Carbon Dioxide
NON-HYDRATE FORMERS
120
9. n-Pentane 10. i-Pentane 11. Hexane 12. Heptane 13. Octane 14. Nonane 15. Decane 16. Toluene
Which Components are present? Please list Hydrate formers first1 8
Enter the MOLE FRACTIONS of each Component :
Mole Fraction of Methane : 0.8470
Mole Fraction of Carbon Dioxide : 0.1530
THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE
(1) MAIN Program for Equilibrium Hydrate Predictions (2) Display CURRENT Feed Composition (3) Change FEED Composition (4) Change Program UNITS (5) DISCARD all Data and begin NEW Problem (6) Exit HYDOFF Program
1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
1
Enter the required Temperature (in F)40.01
THREE-PHASE (Lw-H-V) EQUILIBRIUM CONDITION
Temperature : 40.01 F Experimental pressure Equilibrium PRESSURE : 496.75 psia 494.6 psia
Press RETURN to Continue . . .
Equilibrium Hydrate : STRUCTURE I
Composition of Phases at Equilibrium
FEED VAPOR HYDRATE Methane .8470 .8470 .7222 Carbon Dioxide .1530 .1530 .2778
Press RETURN to Continue . . .
121
Fractional Occupancy of Cages
SMALL LARGE Methane .7737 .6610 Carbon Dioxide .1034 .3191
Do you wish to do another calculation at the SAME composition? (No=1 Yes=2)1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
5
Enter the MOLE FRACTIONS of each Component :
Mole Fraction of Methane : 0.823
Mole Fraction of Carbon Dioxide : 0.177
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
3
Enter the required Temperature (in F)47.93
Enter the WEIGHT PERCENT of Salt5.02
THREE-PHASE (Lw-H-V) EQUILIBRIUM CONDITION
Inhibitor : 5.02 wt% NaCl
Temperature : 47.93 F Experimental pressure Equilibrium PRESSURE : 980.03 psia 1012.4 psia
122
Press RETURN to Continue . . .
Equilibrium Hydrate : STRUCTURE I
Composition of Phases at Equilibrium
FEED VAPOR HYDRATE Methane .8230 .8230 .7150 Carbon Dioxide .1770 .1770 .2850
Press RETURN to Continue . . .
Fractional Occupancy of Cages
SMALL LARGE Methane .8028 .6566 Carbon Dioxide .1136 .3305
Do you wish to do another calculation at the SAME composition? (No=1 Yes=2)1
PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS
(1) PRESSURE PREDICTION at a given TEMPERATURE(2) Pressure prediction at given T with Methanol(3) Pressure prediction at given T with Salt (NaCl)(4) Pressure prediction at given T with Salt+MeOH
(5) Change FEED Composition(6) Change UNITS(7) Return to MAIN Menu(8) Quit HYDOFF
7
THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE
(1) MAIN Program for Equilibrium Hydrate Predictions (2) Display CURRENT Feed Composition (3) Change FEED Composition (4) Change Program UNITS (5) DISCARD all Data and begin NEW Problem (6) Exit HYDOFF Program
6End of run : HYDOFFStop - Program terminated.
123
B.2. XPAND
B.2.a. Program Overview
This program is used to calculate Joule - Thomson cooling of a gas withexpansion across a restriction, such as a control valve. Please note that this programcan only calculate gas expansions which contain methane, ethane, propane, n-butane,i-butane, and i-pentane. The program will not accurately calculate expansions forgases containing nitrogen, carbon dioxide, or hydrogen sulfide.
B.2.b. Running the Program
The file is located in the floppy which has been attached to this handbook. Toinstall XPAND:
1) Insert the disk into the drive.2) Copy the file XPAND.EXE from the disk to the hard drive.3) Obtain/copy the file DOSXMSF.EXE to the same hard drive directory.
After copying, to access the program on your computer, you must be in MS-DOS or a Windows MS-DOS prompt. To run XPAND, do the following:
1) Locate the directory which contains XPAND.EXE and DOSXMSF.EXE2) Type “XPAND”
The program will run and with the initial display “Enter the number ofcomponents”. Execute the program through the following steps:
1) Enter the number of components in the expanding gas. The value entered must bebetween 1-6.
2) A menu will be displayed listing six different gas components. Select thecomponents which are present in the natural gas by entering the number correspondingto each component and pressing <Enter (or) Return>. Continue to do this until all thecomponents in the gas are entered.
3) A screen appears requesting input of the mole fraction of each component specifiedin the previous screen. After entering each value, press <Enter (or) Return>.Note: The composition of the gas has to be entered on a mole fraction basis and noton a mole % basis.
4) A prompt appears requesting you to enter the followinga) the upstream pressure (psia) before the gas expansion,b) the upstream temperature (oR) before the gas expansion, and
124
c) the downstream pressure (psia).Press <Enter (or) Return> after each entry.
5) A prompt appears requesting input of a first guess (oR) of the downstreamtemperature T2. This guess is the decreased temperature after expansion.
Once T2 is entered, a table appears listing the initial conditions and the ∆Hacross the expansion. For Joule-Thomson cooling, at the correct T2 the ∆H across theexpansion should be negligible (zero). Consequently, guesses for T2 should be inputuntil the ∆H is within ±0.500 BTU/lbmol. Once this is done, record the XPAND initialand final conditions, before pressing enter to leave the program.
B.2.c. Output from the Program
This method may be used to get the final temperature upon expansion of a gasfrom an upstream temperature and pressure to a downstream pressure. However,because the expansion curves are not linear in pressure and temperature, repeat thisprocess with the same upstream temperature pressure, but with several intermediatedownstream pressures. Plot the ∆H=0 expansion pressure-temperature line todetermine an intersection with the hydrate formation line, obtained using HYDOFF.
Example 1 - Step-by-step calculation of the gas expansion found in Example 12,Section II.F.3. These steps were used to calculate the final temperature of a gasexpanded from 1500 psia, 100 oF to 300 psia.
Gas Composition: Component Mole %
Methane 92.70 Ethane 5.30 Propane 1.40 i-Butane 1.40 n-Butane 0.34 i-Pentane 0.14
Enter the number of Components:6
Which components are present?1= CH4, 2= C2H6, 3= C3H84= i-C4H10, 5= n-C4H10, 6= i-C5H12
Component 1:1Component 2:2
125
Component 3:3Component 4:4Component 5:5Component 6:6
Enter the mol fraction of each component.Methane:0.927Ethane:0.053Propane:0.014i-Butane:0.014n-Butane:0.0034i-Pentane:0.0014
Enter P1 (psia):1500Enter T1 (R):559.7Enter P2 (psia):300
Input your guess for T2 (R) 1st Guess(Enter “0” to exit the program).520
8.336287E-01 9.461145E-01P1 = 1500.000 psia T1 = 559.700 RP2 = 300.000 psia T2 = 520.000 R
1st delta H = 891.234 BTU/lbmolIdeal gas delta H = -376.414 BTU/lbmol2nd delta H = 201.219 BTU/lbmolTotal delta H = 313.602 BTU/lbmol
1st delta S = .179 BTU/lbmol-RIdeal gas delta S = 2.501 BTU/lbmol-R2nd delta S = .059 BTU/lbmol-RTotal delta S = 2.620 BTU/lbmol-R
If the above values are unsatisfactory, enteranother guess for outlet temperature indegrees Rankine.
Input your guess for T2(R) 2nd Guess(Enter “0” to exit the program).500
8.336287E-01 9.377816E-01
126
P1 = 1500.000 psia T1 = 559.700 RP2 = 300.000 psia T2 = 500.000 R
1st delta H = 891.234 BTU/lbmolIdeal gas delta H = -562.102 BTU/lbmol2nd delta H = 216.348 BTU/lbmolTotal delta H = 112.784 BTU/lbmol
1st delta S = .179 BTU/lbmol-RIdeal gas delta S = 2.136 BTU/lbmol-R2nd delta S = .070 BTU/lbmol-RTotal delta S = 2.245 BTU/lbmol-R
If the above values are unsatisfactory, enteranother guess for outlet temperature indegrees Rankine.
Input your guess for T2(R) 3rd Guess(Enter “0” to exit the program).488.7
8.336287E-01 9.324399E-01P1 = 1500.000 psia T1 = 559.700 RP2 = 300.000 psia T2 = 488.700 R
1st delta H = 891.234 BTU/lbmolIdeal gas delta H = -665.909 BTU/lbmol2nd delta H = 225.689 BTU/lbmolTotal delta H = -.364 BTU/lbmol
1st delta S = .179 BTU/lbmol-RIdeal gas delta S = 1.926 BTU/lbmol-R2nd delta S = .078 BTU/lbmol-RTotal delta S = 2.027 BTU/lbmol-R
If the above values are unsatisfactory, enteranother guess for outlet temperature indegrees Rankine.
Input your guess for T2(R)(Enter “0” to exit the program).0
The 3rd guess of T2 = 488.7 oR resulted in a XPAND calculation of ∆H = - 0.364BTU/lbmol for the 6 component gas mixture. This value of Total delta H is sufficientlyclose to zero indicating an isenthalpic expansion process.
This result indicates that a pressure drop from 1500 psia, 100 oF to 300 psiawill cause a gas temperature reduction to 29 oF (488.7 oR). Several such calculationsat intermediate downstream pressures should be done, because the expansion P-T lineis non-linear. The intersection point of the P-T expansion line (obtained from severalXPAND calculations) with the hydrate formation line (obtained from HYDOFF) willdiffer from the intersection point obtained by just using a straight line drawn between
127
the two end points for the P-T expansion (1500 psia, 100 oF, and 300 psia, 29 oF) andthe hydrate formation line
128
Appendix C - Additional Case Studies ofHydrate Blockage and Remediation
Case Study C.1*1
Placid experienced a hydrate plugging problem in an export pipeline. Theprospect was located at Greens Canyon Block 29 in the Gulf of Mexico in 1527 ft ofwater. A flexible line was installed between the floating production platform to thetop of a rigid riser, located 200 ft below the water line. The flexible pipe was 12 inchID and 16 inch OD with a working pressure rating of 2160 psi. The export linecarried gas and condensate over a distance of 52 miles. Flowing conditions prior tothe blockage were 12 MMSCFD of gas, 5500 BOPD condensate. The API oil gravitywas 49. The gas gravity was 0.68. The pipeline inlet conditions were 70oF and 1050psi.
Over the first few weeks of production, the wells did not produce significantquantities of water. To save operating costs, the gas dehydrators were shut down.When additional wells were brought onstream, there was some residual water-basecompletion fluid being produced. When the wet gas and condensate entered the coldexport line (65oF), water condensed and accumulated at the bottom of the catenaryloop in the flexible line at 200 ft below the surface. Since the line was not beingpigged, water was being accumulated in this low spot. The high pressure gas exposedto the cold water in the flexible line formed a complete hydrate blockage over aperiod of 14 hours, causing the line pressure to increase to 1800 psi before productionwas stopped.
The blockage was located by venting the gas above the plug and filling thevoid with liquid. The volume of liquid and pressure was recorded. The volume offluid required to fill the line corresponded to approximately 200 ft of pipeline,suggesting that the blockage was located near the surface. The blockage length wassuggested to be 8 to 10 ft long. The export line was depressurized on both sides andthe gas dissociated from the hydrates was vented. The line was successfully piggedwith the product gas and condensate the next day. This incident resulted in three daysof production downtime at an operating cost of $40,000.
To prevent hydrate formation three changes were made to the pipelineoperations:
-methanol was injected-gas was continuously dehydrated and-the line was cleaned periodically with foam pigs.
1 Studies from DeepStar II.A. CTR 208A-1 by Mentor Subsea (1996) denoted by “*”
129
Case Study C.2*
Chevron had a 4 inch OD, 2200-ft long gas flowline plugged with hydratesduring the winter. This flowline is in the Whitney Canyon field located in the CarterCreek area of Wyoming. The flowing conditions were 120°F and 360 psig at thewellhead. The ground surface temperature was -20°F, which was well below thehydrate formation temperature at 360 psig.
The flowline is wrapped with heating tape and insulation to keep the linewarm enough to prevent freezing or hydrate formation. Before this blockageoccurred, there were no hydrate inhibitors used. A corrosion inhibitor was used toprevent corrosion. The line is not equipped for pigging. The line ID is 3.826 inchwith a working pressure limit of 1800 psi. The flowline material is carbon steelA333. The heat input was lowered to conserve electrical energy consumption.However, there was no mechanism to monitor the fluid temperature throughout theline to insure that hydrates would not form as the heat input was reduced, a blockageoccurred.
A combination of depressurization, chemical, and thermal techniques wasused to remove the plug. First, the pressure on both sides of the plug was equalized sothat the plug would not move like a projectile. Then, the pressure on both sides of theplug was reduced. Methanol was injected upstream of the hydrate plug. Then, the linewas heated using the heating tape. This was effective in dissociating the hydrate plug.Production was shut down for one day for this remedial operation.
There were several lessons learned from this experience. Future operationsconsidered the use of hydrate inhibitors in the winter months. Currently Chevron isinstalling pumps to inject a kinetic inhibitor or alternative cost-effective chemicals.
Case Study C.3*
In Chevron's platform operations in the Gulf of Mexico, typically, hydratesform in the gas-lift distribution valves on the platform. The gas is generally notdehydrated. In the winter as the gas is throttled through the distribution valve, theJoule-Thomson cooling across the valve drop causes hydrate formation (see SectionII.E). The gas pressure is approximately 1100 psi. The problem is usually not severe.Since surface access is usually available to the blocked location, methanol can beinjected to clear the blockage in the line. To prevent this problem, typically,methanol is injected. One solution recently being tested is to vary the gas flow rate tokeep the valves and gas distribution lines warm enough to keep them above thehydrate formation temperature.
130
Case Study C.4*
Chevron reported a hydrate problem in their Carter Knox field in SouthCentral Oklahoma. Hydrates formed in an uninsulated 4 inch Schedule 80 (4 inch ID,4 ½ inch OD) sales gas line. Flowing wellhead conditions were 105°F and 5750 psi.After choking the well stream to 620 psi at the production unit, the temperature dropsto approximately 62°F at the pipeline inlet. The production unit is designed toremove liquids from the well stream but the gas is saturated with water vapor andthere is always some liquid carryover into the vapor phase. In the winter when theambient temperature is in the upper 40's, the gas cools rapidly due to the coldenvironment. Before hydrates formed, there was no methanol or other chemicalsinjected at the wellhead or at the processing unit. The well was flowing 200 bbl/dayof oil (API 57) and 7.5 MMscf/d of gas. Water production rate was 10 bbls/day.
Two flow meters were installed about 120 ft downstream from the productionunit on the sales line. One meter is 4 inch ID with a 21/4 inch orifice plate and another meter is 3 inch ID with a 21/8 inch ID orifice plate. Additional pressure drop occurred under flowing conditionsat the second meter. This caused hydrates to form at the second meter. In fact, thehydrate accumulation near the meter caused an erroneous flow reading that deviatedfrom the first meter. This was an early indicator of the hydrate formation and it wasdetected before a complete blockage occurred. It took several hours for the hydratesto form.
To remove the hydrate plug, the line was depressurized and a pump injectedmethanol into the line. The production unit was pre-heated to 190°F prior to start-up.It took four hours to completely remove the hydrate accumulation. Furthermore,production was shut down for about eight to ten hours. Based on this experience,methanol is currently injected at the rate of 10 gallons/day whenever ambienttemperature drops below 50°F. The operator is currently considering changing the 3inch ID flow meter to a 4 inch ID flow meter to eliminate the restriction in the salesline.
Case Study C.5*
Chevron reported several incidents of hydrate blockages in onshore gasgathering lines in Canada. In one incident, a complete blockage formed in a 6 inch,15 mile pipeline. The pipe was X42, rated to a working pressure limit of 1000 psi.The line was insulated with a polymer coating which is sufficient to keep the gasabove the hydrate formation temperature under flowing conditions. The condensatecontent was approximately 20 bbls/MMscf. Although there was no free water, thegas was saturated with water vapor at the pipeline inlet pressure and temperature.The condensed water contributed to forming the hydrate plug. Ambient temperatureis approximately 3 to 5°C (37 to 41°F). The blockage occurred during an extended
131
shut-in period over a 300-ft section underneath a road crossing. Previously, hot tapshad located a blockage in the same location. While hot tapping was an option, in thiscase, it was considered too risky. Furthermore, hydrates do not typically form inthese 6 inch lines if depressurized within the first 24 hours.
To remove the blockage, two methods were used simultaneously. First, theline was depressurized on both sides of the plug. Then, a welding rig appliedelectrical current directly to the 300-ft section of the steel pipe. The line was heatedto 20 to 25 °C (68 to 77°F) using the welding rig. This approach was effective inmelting the hydrate plug. The remedial operation took two days to complete.
Case Study C.6*
LASMO experienced a wax and hydrate combination in its Staffa field in theUK sector of the North Sea in 1993. A single, uninsulated, 8 inch flowline wasinstalled between two satellite wells and a minimum processing platform facility(Ninian Southern Platform), located 6.3 miles away. Furthermore, there was nocapability of round-trip pigging the line because a single line was used. The seabedterrain near the tree was uneven and the flowline passed over another flowline about1.2 to 1.9 miles from the tree.
Production conditions were 6000 BOPD with a GOR of 1600 scf/bbl, 0.5 to1% water cut. The produced fluid consisted of a high GOR, high API gravity crudewith some water. Fluids were produced from the reservoir by a pressure declinemechanism. The average cloud point temperature of the crude oil was 79°F. Thewax content in the crude oil was 5%. The flowing wellhead conditions were 942 to1595 psia and 122 to 194°F.
Due to the very high heat losses to the sea through the uninsulated line, theunseparated multi-phase stream cooled to the seabed temperature within 1.2 to 1.9miles from the tree. The fluid arrived at the platform at a temperature of 44°F, whichwas well below the wax cloud point temperature.
Without thorough documentation, it is believed that hydrate formation (due toerratic methanol injection) might have served as a nucleation point to cause waxprecipitation in this line. In any case, wax deposited in the flowline within a period ofseveral days after production was started. Even though certain paraffin inhibitorswere used, they were not completely effective. Periodically, the flowline was soakedwith chemical solvents without much success. Sometimes, pressure was applied toforce the plug, but this actually exacerbated the problem by accumulating the paraffininto a ball. Thermochemical, heat generating chemicals were considered, but wererejected because they were considered relatively new technology.
132
As a contingency plan, LASMO developed an inductive heating coil to bedeployed using an ROV to heat the flowline and melt the wax inside the line.Although this technique was developed, it was never implemented in the field. Twoproblems with this technique were that a significant amount of power and time wererequired to heat the flowline and its contents. Furthermore, even after melting thewax and flowing it, it could cool and re-deposit before arriving at the platform.
Approximately 1.2 miles of the pipeline, filled with a wax blockage, was cutout and replaced. Even after replacing the blocked section of the line, the linebecame plugged with wax a second time. Injection of chemical inhibitors, methanolor solvent soaking did not work.
In 1995 due to multiple problems with hydrates and wax, LASMO abandonedthe field. Repeated attempts to clear the blockages with chemical such as methanolhave failed and the operated decided that it was not economical, considering theamount of reserves remaining, to replace another section of pipe as was done in 1993.
Case Study C.7*
Texaco experienced a hydrate plug in a 12-3/4 inch gas export line at aplatform, located in Garden Banks 189. The water depth is 725 ft. The line connectsto a larger gas transportation line located on the seafloor. In this case, the gas was notdehydrated sufficiently before pumping the gas into the export line. As a result, thewater vapor condensed and settled out in an U-bend at the bottom of the riser. Thecondensed water collecting at the low spot formed hydrates. In this case, hydratesformed very rapidly and formed a near-complete blockage before it was detected.The line injection pressure rose very rapidly.
To remove the hydrate plug, the gas was vented from the platform end andmethanol was lubricated down the riser. The line had a check valve downstream ofthe riser to prevent gas from backflowing to the platform. After injecting somemethanol, the hydrates completely melted and the line was cleared. A total of twentyto thirty 55-gallon drums of methanol was used for the entire operation. Productionof 8000 bbls of liquid/day and 70 MMscf/d from the platform was shut down for twoto three days during this remedial operation.
Case Study C.8*
Texaco reported a hydrate restriction in another gas export line from aplatform at Greens Canyon Block No. 6 in 600 ft. of water. In this case, hydratesslowly accumulated in a 10-3/4 inch line over a period of several days. Whileproduction was not shut down, two actions was taken to remove the restriction: (1)
133
the gas dehydrator was turned on to remove water vapor from the gas stream and (2)methanol was injected into the gas export line.
Case Study C.9*
Texaco also reported a gas hydrate blockage in an instrument isolation valveblock in their Strathespay field in the North Sea. However, there have been noreports of hydrate blockage in the flowline because the line is adequately insulated.This field is located in 442 ft of water. The valve block has a 1/4 inch ID port leadingto a pressure transducer. Since the fluid is static in this section of the line, theproduced gas had water vapor that condensed and formed hydrates. The valve blockand pressure port is uninsulated and exposed to very cold seawater (4°C). Thehydrate blockage resulted in erroneous pressure transducer readings.
To remove this blockage, the line was purged with methanol. Periodically,the line is now purged with methanol to prevent this problem. This workoveroperation, however, is undesirable and increases operating cost.
One design flaw with this system is that the transducer line (1/4 inch ID) issituated above the valve block. Even if this line is periodically filled with methanol,the fluid will drain out and into the flowline. This will allow the wet gas to enter thetransducer line and plug it with hydrates. One design option is to change theorientation of the valve block so that the transducer line is connected to the bottom-side of the valve block instead of the top side. With this configuration, the line can befilled with an oil-based gelled fluid, mixed with methanol, glycol or an oil-based fluidbetween the flowline and the transducer sensor. Otherwise, it may fill with water,causing hydrate formation. In deepwater systems where transducers may be changedas part of a larger system, isolation valves may not be necessary.
Case Study C.10*
Elf Norge has reported hydrate formation in their North East Frigg subseaflowline. The 16 inch flowline transported gas condensate from a subsea templatewith six wells, located 11.1 miles from the Frigg platform.
During some period, only one well was flowing at a rate of 35 MMscf/d. Atthis low gas flow rate, most of the water and condensate settled out and accumulatedin the pipeline. After a few days, the gas flow rate was increased by starting threeother wells. After the gas flow rate increased to 70 MMscf/d, the pressure and liquidlevel in the inlet gas-liquid separator became unstable. The wells were shut down.The separator was found filled with hydrates. Samples taken from the separatorcontained large, solid blocks of hydrates, which took about one day to melt.
134
Analysis of the liquid samples showed that the methanol content was 11-wt%,which was well below the 26-wt% required to avoid hydrate formation. However, Elfreported that the flowline did not plug with hydrates although it experiencedsubcooling up to 6°C. Hydrates were found just downstream of the choke on theplatform. Due to Joule-Thomson cooling (see Section II.E) the gas/water mixtureexperienced the lowest temperature downstream of the choke.
Before re-starting production, the separator was depressurized and circulatedwith steam to remove the hydrates. About 9000 gal of methanol were injected intothe pipeline inlet, the outlet and upstream of the pipeline outlet choke. An additional21,000 gal of methanol was injected during the first two days of restart, when the gasflow rate was gradually re-established.
The liquid outlet valve of the inlet separator was severely eroded during thehydrate formation period. This might have been due to a combination of metallicparticles, scale, or hydrate crystals flowing at high velocities through the valve. Thevalve had to be replaced. Another reason for forming hydrates downstream of thechoke was the lack of an upstream heater. In many subsea completions, a heater isinstalled upstream of the separator and choke to prevent hydrates or wax formationand to improve the separation efficiency.
Case Study C.11*
The following information was provided by Marathon on gas hydrateformation observed in a gas export pipeline from their Ewing Bank 873 platform inthe Gulf of Mexico:
"Hydrate formation occurs in the gas export line from the Ewing Bank 873platform The line leaves the platform and contains a 900-ft deep loop before joininga subsea "T" connection. The line is 8 inch nominal size. The water depth ranges from775-ft at the EW 873 platform to a maximum of 950-ft then 470-ft at the subseaconnection. Seafloor temperature is estimated to be 55°F. Hydrate formation isinferred from pressure buildup in the line, and the fact that methanol can besuccessfully used to remediate. Methanol is pumped continuously for inhibition atapproximately 140 gal/day for 32 Mmscf/d. The pressure drop in the line is afunction of flow rate. It is normally in the range of 50 to 100 psi, depending on flowrate. It can be modeled accurately. If it increases much beyond the normal level (sayan additional 30 psi), then a slug of methanol is periodically pumped. The hydraterestriction appears to be between the EW873 platform and the low point. Pigging hasnot been attempted, for a variety of reasons, but primarily due to high risk forminimal benefit. Methanol is cheap and low risk. The routine technique ofdepressurizing the line is not used at EW 873 because shutting-in production wouldbe required."
135
Case Study C.12*
Phillips reported gas hydrate plugging problems in their Cod pipeline in theNorth Sea. The pipeline is 47 mile, 16 inch (ID=15.124 inch) carbon steel, designedto transport gas and gas condensate from the Cod platform to the Ekofisk center. Theliquid is a light hydrocarbon with a specific gravity of 0.66. The current Codproduction is approximately 35 MMSCFD and 1700 BPD of condensate.
Gas hydrates completely plugged the Cod pipeline several times. In March1978 hydrates formed and a pig became stuck in the hydrate accumulation. Thehydrates were removed by depressurizing the line. The line was backflowed in anattempt to remove the pig. The backflow attempt was unsuccessful. While the pigsremained in the line, the restriction did not prevent the gas flow. A slug of 1700gallons of methanol was pumped to try to dissolve all the hydrates in the line. Duringthe re-start, methanol was continuously injected into the pipeline.
On the Cod platform, even though the gas stream was dried adequately, theliquid condensate stream was not dried properly. Therefore, the wet condensatestream mixed with the high-pressure gas to form hydrates in the pipeline. Since 1981the operating pressure has declined so that the pipeline is now operating outside thehydrate-formation conditions.
Case Study C.13*
Texaco performed field tests in several of their Wyoming wells to evaluate theuse of PVP, a kinetic inhibitor (see Section II.F.2.b). The kinetic inhibitor can beused at very low concentrations, ranging from 1/2 to 1 wt% instead of using 10 to 50wt% of methanol to achieve the required level of hydrate inhibition.
Prior to the field tests, these Wyoming wells and flowlines were experiencinghydrate plugging problems in the wells and the surface flowlines at methanolinjection rates of 30 gallons/day. Flowing wellhead conditions were up to 2000 psiand 52 to 56 oF. Gas production ranged from 0.8 to 1.4 MM scf/d. Freshwaterproduction rate ranged from 2 to 40 bbls/d.
Methanol was replaced with a 4% polyvinylpyrrolidone (PVP) solution. The4% PVP solution consisted of 4-wt% PVP, 16-wt% water and 80-wt% methanol. ThePVP solution was pumped at a rate of 2 to 21 gallons/day, representing an aqueousphase concentration of less than 0.05 wt%. At these concentrations, the kineticinhibitor was effective in preventing hydrates. This represents a cost savings in theorder of 50% compared to using 100% methanol.
136
Case Study C.14*
Similar to Case Study 13, Texaco conducted another series of field tests inEast Texas to evaluate PVP, a kinetic gas hydrate inhibitor. In this field, tests wereconducted on 4 inch to 6 inch flowlines that were one to eight miles long. The gasflow rate ranged from 1 to 24 MM scf/d. Water flow ranged from 0.8 to 40 bbls/day.
Similar to the Wyoming field tests, hydrates formed rapidly when themethanol rate was greatly reduced. Following depressurization subsequent hydrateplugging was prevented by injecting the kinetic inhibitor at concentrations in therange 0.1 to 0.5 wt% of the aqueous phase.
Texaco has completed extensive testing of kinetic gas hydrate inhibitors inonshore U.S. fields. Many of their fields are currently using kinetic inhibitors toreduce methanol consumption costs. Texaco is continuing to experiment withalternative chemicals for optimizing costs and for application in offshore flowlines.
Combined Case Study C.15
Statoil conducted 19 controlled field experiments of gas hydrate blockageformation and dissociation. A comprehensive summary is listed in the references byAustvik et al., 1995, 1997. The experiments were done in 1994 using a 6 inchtest/service subsea line in their Tommeliten Gamma field. The line is connected tothe Edda platform, located 7.1 miles away from the subsea manifold. Two, 9 inchproduction lines and one 6 inch test/service line are installed to carry the flow from asubsea production manifold. The manifold gathers the flow from six subsea wells.Condensate content is 16wt% and water content is 2wt%.
Nineteen hydrate formation and dissociation experiments were conductedusing the 6 inch test/service line, in three types of experiments as follows:
1. Continuous flow - Statoil lowered the flowing temperature by reducing the flowrate and entered the hydrate region.
2. Continuous flow without methanol injection- Production rate was reduced andmethanol injection is stopped.
3. Re-start after shut-in using four approaches:a. Cool pressurized line; re-start without methanol injection.b. Cool pressurized line; re-start with 5-wt% methanol injection.c. Pressurize line from template side; re-start at high flow rate.d. Pressurize line from platform side; re-start at high flow rate.
137
During these experiments, Statoil measured pressure and temperature at thefollowing places: (1) at the manifold, (2) at the top of the riser upstream of the heater,(3) at the choke, and (4) in the separator. Statoil also used two gamma densitometersto detect the arrival of slugs and hydrate lumps on the platform. A thermocamera wasused to detect the temperature profile of the topside lines and to detect ice/hydrateformation.
Table C.1 summarizes the observations in these field tests and operations usedto form and remove hydrate blockages. Following are general conclusions reportedby Statoil on these field experiments:
1. Hydrates formed easily and rapidly after fluid conditions entered the hydrateregion. In some cases, hydrate chunks flowed to the platform and plugged the topsidepiping, valves and bends.
2. Underinhibition of methanol increases rate of hydrate formation and risk ofplugging. Field tests were done at 5-wt% methanol. Laboratory tests performed with10 to 20-wt% methanol also found similar results (reported by Yousif et al., 1996).
3. Hydrate plugs were porous and permeable. hen the plug was subjected to adifferential pressure, the gas from the manifold side flowed through the plug. Thiswas indicated by a gradual drop in pressure at the manifold when the gas was beingvented from the platform side. See Case Study 12 (Section III.B.2.b) for a plug lesspermeable to a Statoil black oil.
4. Gas flow through the plug causes Joule-Thomson cooling leading to additionalhydrates or ice. If additional hydrates or ice form in pore spaces within the hydrateplug, the dissociation rate will be reduced.
5. Combinations of depressurization and methanol injection were effective to removeall plugs. Methanol can be injected at the manifold end or at the platform end.
6. Methods to remove hydrates in the topside piping include injecting methanoland/or spraying warm water on the outside surface. However, heating the pipe fromthe outside can be risky. If the gas released from hydrate dissociation is not properlyvented, the trapped gas may potentially over-pressure the line.
7. Statoil also concluded that the results and recommendations developed from thesefield experiments cannot be directly applied to other fields with different conditionsand fluid compositions.
138
Case Studies C.16 and C.17
This case study summarizes two blocking events in the above Statoil fieldstudy on hydrate formation in the Tommeliten Field of the North Sea.
Case Study C.16. The experiment originated as a depressurized line that wasbrought into production. Methanol was injected continuously into the line throughoutthe start-up process to prevent hydrate formation. When the production reached a rateof 12 MMscf/d, methanol injection was stopped, allowing hydrates to form at thetemperatures of 60oF. The riser temperature was 16oF below the hydrate formationregion. After several partial blocking events, a complete hydrate plug formedapproximately 2.5 miles from the platform. (26 hours after start-up). The pluglocation was estimated from evaluating the rate of pressure change on both plug sides.
Upon blockage, the pipeline was depressurized to dissociate the hydrate plug.Additionally, 3400 gallons of methanol were injected into the wellhead to assist indissociation. Due to the fact that MeOH had to travel five miles, the horizontal natureof the pipeline, small buckling in the pipeline, and liquid present in the pipeline, it isbelieved that the MeOH never reached the plug. One-sided depressurization of thepipeline removed the plug after seven days. The total blockage time was 25 days.
Case Study C.17. The uninhibited line was shut-in at full well pressure andcooled to ambient sea temperature. The line was then started and began producing ata rate of 12MM scf/d without any methanol present. The production line wasmaintained for 40 hours without any hydrate blockage of the line. Several blockingevents occurred topside before a blockage occurred somewhere between the templateand riser. After observing pressure changes on both sides of the plug, it wasdetermined that the plug was approximately 2.5 miles away from the platform. Thehydrate plug was removed through one-sided depressurization. The hydrate plugdissociated slowly, taking nine days before it was removed.
Figure C.1 shows the measured pressure difference across the two plugs inCase Studies C.16 and C.17 as a function of time. These curves have been generatedremoving large pressure fluctuations that occurred while reducing the pressure. Thefigure highlights the change of permeability of the plug as a function of time.
Figure C.2 shows the pressure in the riser during the hydrate removal process.The equilibrium pressure for the hydrate plugs was approximately 200 psi at theambient temperature. Plug 1 was kept under the equilibrium temperature until it wasdissociated. Plug 2 was temporarily kept above the equilibrium point to limit thecooling effects caused by Joule-Thomson cooling. It was thought that this practicehad little effect on increasing the rate of dissociation.
Figure C-1 - Pressure Difference Across Plugs(From Berge, 1996)
0
200
400
600
800
1000
1200
1400
1600
0 50 100 150 200 250 300
Time (hours)
Pre
ssu
re D
iffe
ren
ce (
psi
)
Plug 1 (Case Study 16)
Plug 2 (Case Study 17)
Figure C-2 - Riser Pressure vs. Time(From Berge, 1996)
0
50
100
150
200
250
300
350
400
0 50 100 150 200 250 300
Time (hours)
Pre
ssu
re (
psi
)
Plug 1 (Case Study 16)
Plug 2 (Case Study 17)
139
Case Study C.18
Occidental Oil and Gas Company reported hydrate blockages forming in a gasand associated condensate transport line located in the North Sea. Hydrate plugsusually form in subsea interfield pipelines and in the bottom of incoming risers. Theexport pipeline operates at 4930 psig with a wellhead temperature of 86oF, whichcools down to the ambient sea temperature of 35oF at the outlet. The coldtemperatures place the pipeline within hydrate formation conditions for the gas. Tocombat this, methanol is injected maintaining 25 wt% in the free water phase.
Hydrates form when insufficient amounts of methanol are injected into thepipeline. Early symptoms of hydrate formation are increases in differential pressureand reductions in gas production. A late symptom of hydrate plugs is completeblockage of flow. When blockages occur in the pipeline, two methods are used toremediate plugs. The first method consists of methanol injection and depressurizationof the pipeline from both sides; the usual time needed to remove blockages throughthis method is 1/2-1 days. Depressurization can be avoided by adding large volumesof methanol until dissociation occurs, the usual time needed to carry out thisremediation is 4-14 days.
Occidental also emphasized the importance of minimizing the differentialpressures across the plug to prevent hydrate projectiles. Secondly, they emphasizedthat the pressure must be maintained above 87-145 psig. If the pressure drops belowthese values, the equilibrium temperature moves well below 32oF, causing iceformation. Ice cannot be dissociated through depressurization and consequently takesmore time to remove than hydrate plugs.
Case Study C.19
Amoco reported hydrate plug formation in a 70 mile export pipeline located inthe North Sea. Under normal operating conditions, the gas is dehydrated and thencompressed from 350 psig to 1300 psig. The concentration of water in the gas phaseis usually low enough to prevent free water formation. However, the line had notbeen pigged for three months and during that time offshore process upsets werethought to allow free water into the line. High pressure drops began to form in thepipeline, requiring pigging, but the pig became stuck in the line and had to beremoved through flow reversal. Hydrate slush appeared with the pig on the offshoreplatform. After pigging, the pipeline became completely blocked with hydratesapproximately 30 miles from the offshore platform. The amount of gas used todisplace the pig was utilized to estimate the plugs location.
Two possible tools for pipeline remediation were methanol injection anddepressurization of the pipeline. Methanol could not be used as a remediation methodbecause of the plug’s distant location; consequently two-sided depressurizationbecame the only viable means of dissociating the hydrate plug. Depressurization was
140
carried out over a two week period, and was done in slow steps to prevent any highpressure buildups due to multiple plugs. After eight weeks, the plug was completelydissociated and full production could resume. The line was restarted by slowlysweeping the pipeline with dry gas, building up to high gas rates. The line wasconsistently pigged, first with undersized pigs and then full-sized. No problems werewitnessed during start-up.
The hydrate remediation process lasted eight weeks and cost $500,000 tocarry out. Overall, the plug shut-down production for three months and cost $5.5million due to remediation expenses and loss of sales.
Case Study C.20
Petrobras reported a hydrate blockage in a subsea manifold, located around2000 ft water depth. The manifold was initially loaded with water, and was notdrained and loaded with ethanol prior to production start-up, as is normal practice.Consequently, a hydrate plug formed in the manifold, blocking valves in a productionline. However, production was maintained through a test production line.
Two methods were attempted to dissociate the pipeline. First, ethanol wasinjected into the manifold to begin dissociation. Some dissociation did occur(indicated by pressure increases), but the hydrate plug was still present after 2 days.Depressurization of the manifold was then used to dissociate the plug.Depressurization was carried out on both sides of the plug, dissociating the plug intwelve hours. Start-up of the pipeline was carried out by filling the manifold withethanol and then resuming production.
Overall, the hydrate plug was in the manifold for sixty days, but productionwas maintained throughout that time via a test production line. Duringdepressurization, all production from the wells flowing into the manifold had to beshut down. The total economic loss due to the hydrate was 31,500 bbl oil and thewages of two engineers(1 week) and two technicians (3 days).
Case Study C.21
Barker and Gomez (1989) describe an Exxon experience with a hydrate in awell located in 1,150 ft of water off the California coast. While drilling, gas flowedinto the well from the formation, channeling through the primary cement column at7,750 ft, and the migrating gas entered the freshwater mud at the subsea wellhead.Due to difficulties with the wellhead hanger packoff, the gas influx was stopped byperforating the casing, with a result of severing the drillstring and stripping it upthrough the BOP’s until the severed drillstring end was above the gas sand.
141
A through drillstring perforating gun was then run to shoot the 7 in. casingjust above the gas snad. The gas influx was killed by pumping a 14.2 lbm/gal muddown the drillstring and into the formation at surface pressures up to 3,100 psi. Atthe conclusions of the kill operation, both the chokeline and the kill ine were foundplugged. Subsequent operations were hampered by the inability to use either line.After cementing operations which secured the well bore, the BOP’s were recovered.Hydrates and trapped gas were found in the chokeline and the kill line of the bottomeight riser joints.
Case Study C.22
A second Exxon drilling instance was reportedby Barker and Gomez (1989) in3,100 ft of water in the Gulf of Mexico, with a ocean bottom temperatuere of 40oF.Gas flowed into the well and plugged the choke and kill lines. After four days ofwarm drilling mud circulation, the lower-middle ram-type BOP’s could not becompletely opened or closed, possibly because of hydrates in the ram-block recesses.
The drillstring was perforated about 400 ft above the annular gas/liquidcontact. After coiled tubing was run inside the drillstring, hot mud was circulated andgas was allowed to migrate into the coiled-tubing/drillstring annulus before beingcirculated out of the well. Three sets of successively shallower performations wererequired to remove the gas completely in the annulus.
After all ram-type BOP’s were opened, the drillstring was backed off at 5,000ft. and recovered, and a cement plug was set in the casing. The well was secured andthe BOP’s were pulled, resulting in a recovery of hydrates. Testing of BOP’s at thesurface indicated that the failure was not caused by mechanical failure from theBOP’s which were then free of hydrates.
Case Study 23
Davalath and Barker (1993) described a hydrate problem in 595 ft. of waterlocated offshore South America. The well was completed with a 7 inch casing and3.5 inch tubing. Production was gas and condensate at several hundred barrels perday with a water cut of about six percent. A 15 hour production test was followed bya 25 hour shut-in period to collect reservoir pressure buildup data.
The well was shut-in at the surface, which exposed the tubing to high pressuregas and cold 45oF water, which led to the formation of hydrates. Under theseconditions the tubing fluid was about 29oF below the hydrate formation temperature.Wireline tools were blocked by a bridge inside the tubing string and further pullingcaused separation. Subsequently the lubricator was found to be full of hydrates.
142
Attempts were made to melt hydrates by (1) pouring glycol into the top of thetubing, (2) using heated mud and seawater, (3) increasing the pressure up to 7,000 psiat the surface to break the hydrate plug. The above attempts were unsuccessful andthe authors noted that the pressure increase caused a more stable hydrate, rather thanblowing it from the tubing.
A coiled tubing string was stripped inside the tubing and 175oF glycol wascirculated to the hydrate plug at 311 ft. Direct contact with the hot glycol removedthe hydrate plug but more than 13 days were lost because of this incident.
Case Study 24
Davalath and Barker (1993) also reported hydrate formation during wellabandonment in the Gulf of Mexico. During normal production methanol wasinjected at the subsea tree. After stopping production the flow lines and tree pipingwere filled with seawater and corrosion inhibitor from the surface to the seafloor.During plug and abandonment operations, the operator found ice-like solids inside thetubing bore of the tree at the seafloor and in the annulus bore. The solid hydrateplugs were dissolved by circulating heated CaBr2 brine through a coiled tubing stringrun inside the tubing.
Case Studies 25, 26, 27
Three controlled hydrate field tests were completed on Devon Energy-KerrMcGee 900 psia gas condensate line in the Powder River Basin of Converse County,Wyoming from 1/27/97 to 2/20/97. The object of the tests was to show that one-sideddepressurization can be safely performed in the field. As indicated in the HydratePlug Remediation portion (II) of this handbook, the standard onshore dissociationprocedure is (a) to balance the pressure on both sides and (b) to reduce the balancedpressure to move outside of the hydrate region.
The test line was 4 inch, 17,381 ft long from wellhead to separator-receiver(SRU-10) and pig receiver, and mostly buried to a depth of 5 ft with a groundtemperature of 34oF. Elevation varied over 250 ft. Normally in winter, the flowlineis continually treated with MeOH and pigged daily to prevent hydrate problems.
The pipeline had the following instruments at five sites: (1) the wellhead(Werner-Bolley) with P,T sensors, 1.5” flow orifice, back-P control valve, and piglauncher, (2) 3,7852 ft downstream with P,T sensors and blowdown, (3) 5,395 ftdownstream with P,T sensors, (4) 6,624 ft downstream with P,T sensing, methanolinjection, blowdown capability, and dual gamma-ray sensors to monitor plugvelocity, length, and density, (It was difficult to discern the differences betweenwater, plugs, and condensate) and, (5) 11,483 ft with P,T, sensing. At the end of the
143
line was a Separator-Receiver Unit (SRU-10) which contained a pig receiver andblowdown.
Temperatures were not analyzed because the RTD was an external measurement.However, the pressures at the four sites, the orifice measurement, and the gamma raymeasurements proved invaluable in analyzing hydrate formation and dissociation.
The following steps were used to conduct a test:• Data collection initiated• Methanol injection stopped at the wellhead• Methanol injection begun at site 4• Pig launched at site 1 and received at SRU-10• Blockage formation monitored• Line isolated after blockage formation• Blockage dissociation by blowdown at sites 2,4, or SRU-10.
The average steady state liquid holdup at Site 4 is 3.9%. The liquid in thewater/condensate plugs was between 4.5 and 4.9%. Average superficial gas velocitywas 6.3 ft/s in the pipeline, without blockages.
Case Study 25 (Test 1) had 2 blockages. One relatively impermeableblockage was formed in the cold portion of the line between Sites 4 and 5. The other,more permeable blockage was formed in the warm portion of the line. Both werecleared by blowdown at site 4. The differential pressure across the blockages rangedbetween 112 and 174 psi, corresponding to a total load between 6,300 and 9,800Newtons.
Test 2 was aborted because hydrates formed upstream of site 2 (undesirableform a safety standpoint because site 2 is above ground with 2 ball valves and 2 45o
bends. Hydrates were dissociated by reducing balancing the pressures on either side.
Case Study 26 (Test 3) resulted in a short (25 ft) blockage with lowpermeability, which dislodged and passed site 4 with a speed of 270 ft/s, beforeeroding further down the pipeline. The differential pressure ranged from 271 to 475psi, corresponding to a total load between 15,300 and 26,900 Newtons, about doublethat of more porous blockages.
Case Study 27 (Test 4) had a blockage which formed on the downstream sideof site 4 and then was moved upstream of site 4, via line depressurization at site 2.Each time the plug was driven past site 4, then lodged to form another, less permeableblockage. These plugs were longer (ca. 90 and 175 ft) than those of Test 3.
On the next page is a table summarizing the characteristics of the plugs:
144
Test 1 2 3 4Dates 1/27-31/97 2/1-5/97 2/6-8/97 2/19-20/97Block Time, hrs 85 62 37 143Plug Length, ft NA NA 25 90, 300, 30, 70Max ∆P, psi 174 Aborted 390 475Max Gas SprfclVelocity cm/s
12.07 NA NA 1.15
Max Load, n 9857 NA 2960 26908Leakage, Mass/Load (g/s/n)
0.0015-0.0067
NA 0.00029 0.00038
Max plugVelocity, ft/s
NA NA 270 65
Shr Strss N/cm2 0.13 NA 2.14 2.29
145
Appendix D. Rules-of-Thumb Summary
A summary is presented for all of Rules of Thumb in the handbook, togetherwith the Section from which they were extracted. As indicated at the outset, theseRules-of-Thumb are based upon experience and they are intended as guides for theengineer for further action. For example, using a Rule-of-Thumb the engineer mightdetermine that a more accurate calculation was needed for inhibitor injection amounts,or that further consideration of hydrates was unnecessary. Rules-of-Thumb are notintended to be “Absolute Truths”, and exceptions can always be found; where possiblethe accuracy of the Rule-of-Thumb is provided in the appropriate Section.
Rule of Thumb 1: (Section II.A) At 39oF, hydrates will form in a natural gassystem if free water is available and the pressure is greater than 166 psig.
Rule-of-Thumb 2: (Section II.B.3.a) For long pipelines approaching the oceanbottom temperature of 39oF, the lowest water content of the outlet gas is givenby the below table:
Pipe Pressure, psia 500 1000 1500 2000Water Content, lbm/MMscf 15.0 9.0 7.0 5.5
Rule-of-Thumb 3: (Section II.B.3.b) At 39oF and pressures greater than 1000psia, the maximum amount of methanol lost to the vapor phase is 1 lbm
MeOH/MMscf for every weight % MeOH in the free water phase.
Rule-of-Thumb 4: (Section II.B.3.b) At 39oF and pressures greater than 1000psia, the maximum amount of MEG lost to the gas is 0.002 lbm/MMscf.
Rule-of-Thumb 5: (Section II.B.3.c) The concentration of methanol dissolved incondensate is 0.5 wt %.
Rule-of-Thumb 6: (Section II.B.3.c) The mole fraction of MEG in a liquidhydrocarbon at 39oF and pressures greater than 1000 psia is 0.03% of the molefraction of MEG in the water phase.
Rule-of-Thumb 7. (Section II.E) Natural gases cool upon expansion frompressures below 6000 psia; above 6000 psia the temperature will increase uponexpansion. Virtually all offshore gas processes cool upon expansion, since only a
146
few reservoirs and no current pipelines or process conditions are above 6000psia.
Rule-of-Thumb 8. (Section II.E.3) It is always better to expand a dry gas, toprevent hydrate formation in unusual circumstances, e.g. changes in upstreampressure due to throughput changes.
Rule-of-Thumb 9. (Section II.E.3) Where drying is not a possibility, it is alwaysbetter to take a large pressure drop at a process condition where the inlettemperature is high.
Rule-of-Thumb 10. (Section II.F.1.b) Monoethylene gylcol injection is used whenthe required methanol injection rate exceeds 30 gal/hr.
Rule-of-Thumb 11. Section II.F.2.a) Use of anti-agglomerants requires asubstantial oil/condensate phase. The maximum water to oil ratio (volume basis)for the use of an anti-agglomerant is 40:60 on a volume basis.
Rule-of-Thumb 12. (Section II.F.2.b) PVP may be used to inhibit pipelines withsubcooling less than 10oF for flow lines with short gas residence times (less than20 minutes).
Rule-of-Thumb 13: (Section II.F.2.b) VC-713, PVCap, and co-polymers ofPVCap can be used to inhibit flow lines at subcooling less than 15oF, with waterphase residence times up to 30 days.
Rule-of-Thumb 14: (Section III) Hydrate blockages occur due to abnormaloperating conditions such as well tests with water, loss of inhibitor injection,dehydrator malfunction, startup, shutin, etc. In all recorded instances hydrateplugs were successfully removed and the system returned to service.
Rule-of-Thumb 15: (Section III.A.1) In gas-water systems hydrates can form onthe pipe wall. In gas/condensate or gas/oil systems, hydrates usually form asparticles which agglomerate to larger masses in the bulk streams.
147
Rule-of-Thumb 16: (Section III.A.1) Agglomeration of individual hydrateparticles causes an open hydrate mass which has a high porosity (often > 50%)and is permeable to gas flow (permeability to length ratio of 8.7 - 11 × 10-15 m).Such an open hydrate mass has the unusual property of transmitting pressurewhile being a substantial liquid flow impediment. Hydrate particles anneal tolower permeability at longer times.
Rule-of-Thumb 17. (Section III.B.1.a) A lack of hydrate blockages does notindicate a lack of hydrates. Frequently hydrates form but flow (e.g. in an oilwith a natural surfactant present) and can be detected in pigging returns.
Rule-of-Thumb 18: (Section III.B.2.a) When a hydrate blockage is experienced,for safety reasons, inhibitor is usually lubricated into the line from the platformin an attempt to determine the plug distance from the platform. Attempts to“blow the plug out of the line” by increasing the upstream pressure will result inmore hydrate formation and perhaps rupture due to overpressure
Rule of Thumb 19. Regardless of the method(s) used to dissociate the hydrates,the time required for hydrate dissociation is usually days, weeks, or months.After a deliberate dissociation action is taken, both confidence and patience arerequired to observe the result over a long period of time.
Rule of Thumb 20. (Section III.C) When dissociating a hydrate plug, it shouldalways be assumed that multiple plugs exist both from a safety and a technicalstandpoint. While one plug may cause the initial flow blockage, a shut-in willcause the entire line to rapidly cool into the hydrate region, and low lying pointsof water accumulation will rapidly convert to hydrate at water-gas interfaces.
Rule of Thumb 21. (Section III.C.3) Because the limits of a hydrate plug cannotbe easily located in a subsea environment, heating is not recommended forsubsea dissociation.
Rule-of-Thumb 22. (Section IV.B.1.a) Methanol loss costs can be substantialwhen the total fraction of either the vapor or the oil/condensate phase is verylarge relative to the water phase.
Rule-of-Thumb 23. (Section IV.B.1.b) The cost of a fixed leg North Sea platformsis $77,000/ton.
148
Rule-of-Thumb 24. (Section IV.B.2) In order to achieve a desired heat transfercoefficient of 0.3 BTU/hr-ft2-oF, a non-jacketed system costs $1.5 million permile. Typical costs of insulation via bundled lines are $1.5 -$2.0 million/mile.
149
References
Aarseth, F., “Use of Electrical Power in Control of Wax and Hydrates,” Proc 1997Offshore Technology Conference, paper OTC 8541, Houston, TX, May 5-8, 1997.
Argo, C.B., Blain, R.A., Osborne, C.G., Priestley, I.D., “Commercial Deployment ofLow Dosage Hydrate Inhibitors in a Southern North Sea 69 Kilometer Wet-GasSubsea Pipeline,” SPE 37255, Proc. SPE Int. Symp. on Oilfield Chemistry,Houston, Texas (18-21 February 1997)
Argo, C.B., Osborne, C.G., Personal Communication Estimation of Capital andOperating Cost Associated with Threshold Hydrate Inhibitors, BP SunburyResearch Centre, U.K. July 18, 1997.
Austvik, T., Personal Communication Regarding Safety, Prevention, Remediation andEconomics at Statoil Reseach Center, Trondheim, Norway, July 13 - 15, 1997.
Austvik, T., Hustvedt, E., Meland, B., Berge, L., Lysne, D., “Tommeliten GammaField Hydrate Experiments,” Proc. 7th Inter. Conf. on Multiphase Production,BHRA Group Conf. Ser. Publication 14, Cannes, June 7-9, (1995)
Austvik, T., Hustvedt, E., Gjertsen, L.H.,Urdahl, O., “Formation and Removal ofHydrate Plugs, Field Trial at Tommeliten,” Proc. Gas Processors AsosicationConference, San Antonio, Texas, (March 1997)
Baillie, C., Wichert, E., “Chart Gives Hydrate Formation Temperature for NaturalGas,” Oil & Gas Journal, 37 (April 1987)
Barker, J.W., Gomez, R.K., “Formation of Hydrates During Deepwater DrillingOperations,” J. Petrol. Tech., 41, 297 (March 1989)
Behar, E., Delion, A.-S., Sugier, A., Thomas, M., “Plugging Control of ProductionFacilities by Hydrates,” 1st Internat Conf. on Natural Gas Hydrates, Sloan, E.D.,Happel, J., Hnatow, M. eds New York Academy of Sciences, Vol.715, p 94,(1994)
Berge, L., Gjertsen, L., Lysne, D., “The Importance of Porosity and Permeability ofHydrate Plugs in Pipes,” in Proc. 2nd Intnl. Conf. on Natural Gas Hydrates, p.533, (Monfort, J.P., ed.), Toulouse, 2-6 June (1996)
Bloys, B., Lacey, C., Lynch, P., “Laboratory Testing and Field Trial of a New KineticHydrate Inhibitor,” OTC 7772, Proc. 27th Ann OTC, Houston, Texas May 1-4,(1995)
150
Brown, G.G., “A Series of Enthalpy-Entropy Charts for Natural Gases,” Trans AIME,160, 65 (1945)
Canadian Association of Petroleum Producers (R. King, T. Sharples, J. Stewart, S.Sortland, authors) CAPP Guideline for the Prevention and Safe Handling ofHydrates, 10 pages (January 1994)
Chevron Canada Resources, “Hydrate Handling Guidelines: Safety and Loss ControlManual,” Chevron Internal Report, 27 pages (July 23, 1992)
Corrigan, A., Duncum, S.N., Edwards, A.R., Osborne, C.G., “Trials of ThresholdHydrate Inhibitors in the Ravenspurn to Cleeton Line,” SPE Prod. & Facil., p 250(Nov. 1996)
Davalath, J., Barker, J.W., “Hydrate Inhibitor Design for Deepwater Completions,”Proc. 68th Annual Tech. Conf. of Society Petroleum Engineering, SPE 26532,Houston, Texas, 3-6 October 1993.
Deaton, W.M., Frost, E.M., Jr., Gas Hydrates and Their Relation to the Operation ofNatural-Gas Pipe Lines , 101 pp. U.S. Bureau of Mines Monograph 8, 1946.
DeepStar I CTR 230-1 “Control Systems,” Intec Engineering, 4 Sections and 3Appendices, (December 1992)
DeepStar I CTR 240-1 “Chemical Injection System Study,” Intec Engineering, 4Sections and 1 Appendix, (December 1992)
DeepStar II CTR 221-1, “Evaluation of the Impact of Methanol Recycle/RecoveryFacilities on Offshore Production Systems,” Paragon Engineering Services, Inc., 34pages and 3 appendices, (December 1994)
DeepStar II CTR 223-1,”Deepstar Insulation Requirement for Pipeline Bundles,”Texaco Central Engineering and Purchasing Department ,and Texaco ExplorationProducting Technologty Department (R.W. Barkley, T.L. Dean, S. Kashou,authors), 216 pages, (June 1994)
DeepStar II CTR 230-1, “Operational Experience with Hydrate Formation in LiquidHydrocarbon Lines,” Paragon Engineering, 22 pages and references, (June 1994)
DeepStar II. CTR 640-1, “Pipeline/Flowline Pigging Strategies” H.O. Mohr Research& Engineering, Inc., Tutorial and Review (August 1994)
DeepStar IIA CTR A208-1, “Methods to Clear Blocked Flowlines,” Mentor Subsea(J. Davalath, author), 157 pages and a appendix, (January 1996)
151
DeepStar IIA CTR A209-1, “Hydrate Formation Tests Requirements for MultiphaseOil Systems,” IIT Research Institute, Westport Technology Center International(M.H. Yousif, author) 36 pages, (December 1995)
DeepStar IIA CTR A212-1, “Paraffin and Hydrate Detection Systems,” ParagonEngineering Services, Inc. and Southwest Reserch Institute, 103 pages, (April1996)
DeepStar IIA CTR A601-a, “Insulated Flowline Options Identification Study,” INTECEngineering Company, 23 pages and 5 appendices, (August 1995)
DeepStar IIA CTR A601-b, “Deepwater gulf of Mexico Integrated Towed FlowlineBundle Design Study,” Kvaerner - R.J. Brown, 9 Sections and 2 appendices,(December 1995)
DeepStar IIA CTR A601-c, “Deepwater Gulf of Mexico Insulated Pipe-in-PipeStudy,” Snamprogetti, S.p.A. Offshore Division, 220 pages and 5 annexes,(December 1995)
DeepStar IIA CTR A601-d, “Non-Jacketed Insulation Coating,” Mentor Subsea (J.Davalath, author),16 pages and 2 appendices, (February 1996)
DeepStar IIA CTR A900-3, “GC-184 Paraffin/Hydrate Inhibition Study - Phase Two,”Conoco, Inc., (T.S. Brown author) (June 1992)
Edwards, A.R., Personal Communication Regarding the Use and Economics ofThreshold Hydrate Inhibitors, BP Dimlington Terminal , U.K., (July 17, 1997)
Englezos, P., “Kinetics of Gas Hydrate Formation and Kinetic Inhibiton in OffshoreOil and Gas Operations,” Proc. 5th Int. Offshore & Polar Eng. Conf., , pg 289, theHague, Netherlands (June 11, 1995)
GPSA Engineering Data Book, Revised 10th Edition, Gas Processors SuppliersAssociation, 6526 East 60th Street, Tulsa, Oklahoma 74145
Gjertsen, L.H., Austvik, T., Urdahl, O., Duus, R., “Removal of a Gas Hydrate PlugFrom a Subsea Multiphase Pipeline in the North Sea,” Proc. BHR Group 1997Multiphase ‘97 Conference, Cannes, France, (June 18-20, 1997)
Grainger, M., “TR Oil Services Perspectives on the Use of Alternate HydrateInhibitors,” written personal communication to E.D. Sloan, (September 3, 1997)
Hatton , G.J., Barajas, A.M., Kuhl, C.A., Hydrate Plug Decomposition Test Program,Final Report, SwRI Project 04-8217, October 1997, Prepared for DeepStar 3204Subcommittee.
152
Houston,C., Personal Communication: Survey of USA Methanol Usage, July 31, 1997
Katz, D.:L., “Prediction of Conditions for Hydrate Formation in Natural Gases,”Trans. AIME, 160: 140 (1945)
Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenbaas, J.R.,Weinaug, C.F., Handbook of Natural Gas Engineering, McGraw-Hill Book Co.,Inc., New York, 802 pp. (1959).
Kelkar, S.K., Selim, M.S., Sloan E.D.,“Hydrate Dissociation Rates in Pipelines,” Proc.13th Symposium on Thermophysical Properties, June 22-27, 1997, Boulder,Colorado
Kent, R.P., Coolen, M.E., “Hydrates in Natural Gas Lines,” Mobil Internal Report, 7pages (1992)
Lingelem, M.N., Majeed, A.I.,m Stange, E., “Industrial Experience in Evaluation ofHydrate Formation, Inhibition, and Dissociation in Pipeline Design and Operation,”1st Internat. Conf. on Natural Gas Hydrates, Sloan, E.D., Happel, J., Hnatow, M.eds., New York Academy of Sciences, Vol.715, p 75, (1994)
Loh, J., Maddox, R.N., Erbar, J.H., “New Hydrate Formation Data RevealDifferences,” Oil & Gas Journal, 81(20), p. 96 (1983)
Lynch, P., “Orwell Field Pipeline Blockage Report, April - June 1996,” ARCO BritishLtd. Report, 23 pages, November 1996
Lysne, D., An Experimental Study of Hydate Plug Dissocation by Pressure Reduction,D.Ing. Thesis, Norwegian Institute of Technology, University of Trondheim (1995)
Makogon, Y.F., Hydrates of Natural Gas, Pennwell Publishing, 237 pages, (1981)
Makogon, Y.F., Hydrates of Hydrocarbons, Pennwell Publishing, 482 pages (1997)
Manning, F.S., and Thompson, R.E., Oifield Processing of Petroleum: Volume One:Natural Gas, Pennwell Publishing, Tulsa (1991)
Monfort, J.P., ed, Proc. 2nd Intnl. Conf. on Natural Gas Hydrates, F. Foucaud,Secretariat, 18 Chemin de la Loge, 31078 Toulouse Cedex, France 2-6 June, 1996
Ng, H.-J., Robinson, D.B., “Equilibrium Phase Composition and Hydrating Conditionsin Systems Containing Methanol, Light Hydrocarbons, Carbon Dioxide, andHydrogen Sulfide,” GPA Research Report RR-66, Gas Processors Association,(joint with Canadian Gas Processors Association) Tulsa, (April 1983)
153
Ng, H.-J., Chen, C.-J., “Vapour-Liquid and Vapour-Liquid-Liquid Equilibria for H2S,CO2, Selected Light Hydrocarbons, and a Gas Condensate in Aqueous Methanol orEthylene Glycol Solutions,” GPA Research Report RR-149, Gas ProcessorsAssociation, Tulsa, Gas Research Institute, Chicago (1995)
Ng, H.-J., Chen, C.-J., Robinson, D.B., “The Influence of High Concentrations ofMethanol on Hydrate Formation and the Distribution of Glycol in Liquid-LiquidMixtures,” GPA RR-106, Gas Processors Association, Tulsa, (April 1987)
Nielsen, R.B., Bucklin, R.W., “Use of Methanol for Hydrate Control in ExpanderPlants,” Proc. Gas Conditioning Conference, Norman, OK (1983)
Notz, P.K., “Discussion of the Paper, ‘The Study of Separation of Nitrogen fromMethane by Hydrate Formation Using a Novel Apparatus,’” 1st Internat Conf. onNatural Gas Hydrates, Sloan, E.D., Happel, J., Hnatow, M. eds New YorkAcademy of Sciences, Vol.715, p 425, (1994)
Notz, P.K., Texaco Technical Memorandum (TM 94-0145) on Relative InhibitorCosts, July 26, 1994
Notz, P.K., Bumbgartner, S.B., Schaneman, B.D., Todd, J.L., “The Application ofKinetic Inhibitors to Gas Hydrate Problems,” OTC 7777, Proc. 27th Ann OTC ,Houston, Texas May 1-4 (1995) and SPE Prod & Facil, 256 (November 1996)
Polderman, L.D., "The Glycols as Hydrate Point Depressants in Natural Gas Systems,"Proc. Gas Conditioning Conference, Norman, OK (1958)
Robinson, D.B., Ng, H.-J., “Hydrate Formation and Inhibition in Gas or GasCondensate Streams,’ J. Can. Petrol. Technol., 25(4), 26 (1986)
Sas-Jaworsky, A., II., Blount, C.G., Tailby, R.J., “Coiled Tubing...Operations andServices,” World Oil, pg 55, (June 1993)
Shuler, P.J., Chevron Production Technology Co., Personal Communication ofHYDCALC program (June 10, 1997)
Sloan, E.D., “The Colorado School of Mines Hydrate Program,” Proc. 64th Ann.GPA Convention, Gas Processors Association, Houston (March 1985)
Sloan, E.D., Jr., Clathrate Hydrates of Natural Gases, Marcel Dekker, Inc., NewYork, (Second Edition) 704pp (1998)
Sloan,E.D., Happel, J., Hnatow, M.A., eds, (First) International Conference onNatural Gas Hydrates, Annals of New York Academy of Sciences, 715, 1994
154
Stange, E., Majeed, A., Overa, S., Experimentations and Modeling of the MultiphaseEquilibrium and Inhibition of Hydrates,” Proc. 68th Annual GPA Convention, SanAntonio, Texas (March 1989)
Texaco (J. Todd, K. Barbin, E,. Busby, S. Hourcade, D. Hall, B. Peterson) ReliabilityEngineering - Gas Freezing and Hydrates, (a handbook for operating personnel), 16Sections (1996)
Todd, J.L., Personal Communication, June 18, 1997
Townsend, F.M., Reid, L.S., Hydrate Control in Natural Gas Systems, L.S. Reid andAssoc, P.O. Biox 1188, Norman, OK 73070, (September 23, 1978)
Urdahl, O., Personal Communication on Safety, Prevention, Remediation, andEconomics at Statoil Reseach Center, Trondheim, Norway, July 14, 1997.
Xiao, J.J., Shoup, G., Amoco Letter to G. Hatton, Southwest Research Institute,“OLGA Simulation - Steady-State Results,” September 16, 1996a.
Xiao, J.J., Shoup, G., Amoco Letter to G. Hatton, Southwest Research Institute,“OLGA Simulation - Plug Movement Results,” September 23, 1996b.
Xiao, J.J., Shoup, G., Amoco Letter to G. Hatton, Southwest Research Institute,“OLGA Simulation - Plug Movement Results: Efect of Injecting Condensate onPlug Movement,”November 6, 1996c.
Xiao, J.J., Shoup, G., Amoco Letter to G. Hatton, Southwest Research Institute,“Flow Pattern Maps for the Kerr McGee 4 Inch Pipeline,” February 5, 1997.
Yousif, M., Austvik, T., Berge, L., Lysne, D., “The Effects of Low ConcentrationMethanol Solutions on Hydrate Formation,” in Proc. 2nd Intnl. Conf. on NaturalGas Hydrates, p. 291, (Monfort, J.P., ed.), Toulouse, 2-6 June (1996)
Yousif, M.H., Li,P.M., Selim, M.S., Sloan, E.D., “Depressurization of Natural GasHyrates in Berea Sandstone Cores,” J. Inclus. Phenom. and Molec. Recog., 8, 71,(1990)
