hydrate problems in pipelines

8/12/2019 Hydrate Problems in Pipelines

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Hydrates may be dissociated by means of pressure reduction, heataddition and inhibitor injection. The processes involved in thesephenomena are iinportant, as they are also coupled to potential hazards.The most comprehensive review of gas hydrates can be found in Sloan(1990).

DISSOCIATION PROCESSESIt will be seen that on a small enough scale, the three describedprocesses of gas hydrate dissociation are essentially equivalent.Pressure reductionA schematic description of hydrate dissociation by pressure reduction isshown in Figure I assuming a mixture of oil, gas, water and hydrate.Starting with the pressure and temperature conditions given by point Ain the figure, the pressure is first lowered to the eqUilibrium pressurecorresponding to the ambient temperature (point B). So far nothing hashappened to the hydrate phase. During the next step the pressure islowered to point C, which is below the hydrate eqUilibrium curve. Amolecular description of this effect on the hydrate phase is not found inthe literature. The macroscopic behaviour is however known through afew studies, including work by Lysne (1995). The following descriptionis mainly based on that work.Hydrate dissociation requires energy which is taken as heat from thehydrate phase itself and the surrounding medium. The macroscopicindication of these phenomena is a temperature drop in the part of thesystem which is exposed to the pressure reduction. This is shown inFigure 1 as line C-D. Provided that the pressure is now kept constant, thetemperature in the hydrate phase will be equal to To as long as there isany hydrate left. The hydrate phase, which is at thermodynamicequilibrium, will hence have a temperature constantly below the ambienttemperature, and both convective and conductive heat transfer to thehydrate phase from the surroundings will occur. The rate of dissociationwill be strongly dependent on the heat transfer resistance. Insulation ofa pipeline will slow down the dissociation of a hydrate plug inside itConstant pressure requires that water and gas produced from hydratedissociation are removed continuously. At constant volume conditionsafter the pressure reductions the produced gas and water fromdissociating hydrate will increase the pressure and consequently thetemperature, along the hydrate equilibrium curve, described by curveD-B in Figure 1 At point B, the hydrate phase is at thermal andthermodynamic equilibrium with the surroundings, and the dissociationstops.Temperature increaseFigure 2 shows a schematic description of hydrate dissociation bytemperature increase, still assuming a mixture of .oil, gas, water andhydrate. Starting with the pressure and temperature conditions given bypoint A in the figure, the temperature is first increased to the hydrateequilibrium temperature corresponding to the given pressure, TB Thehydrate is at thermodynamic equilibrium and has not yet started todissociate. As the ambient temperature is increased beyond the hydrateequilibrium curve to Te, the hydrate phase starts to melt.The temperature of the hydrate phase. cannot be higher than theeqUilibrium temperature, and if the pressure is kept constant, thepressure and temperature at point B on Figure 2 persists in the hydrate.However, if the dissociation takes place at constant volume conditions,the water and gas produced from the dissociating hydrate will increasethe pressure. As the pressure inside the constant volume increases, theequilibrium temperature also increases, and the dissociation processfollows curve B-D in Figure 2 until thermal equilibrium with thesurroundings is obtained, and the overall dissociation stops - showingthe same behaviour as for an initial pressure reduction.Inhibitor injectionThe third known method for melting hydrates is inhibitor injection.Among the inhibitors applied for hydrate control in the North Sea,methanol has the ability to dissociate existing hydrates. Figure 3 shows aschematic description of hydrate dissociation by addition of methanol.The main effect is that the thermodynamic equilibrium at a givenpressure is changed towards lower temperatures. The original hydrateeqUilibrium is shown to the right on Figure 3 and the new hydrate

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Figure 1

D

Ta TemperatureHydrate dissociation by pressure reduction.Ta is the ambient temperature

eqUilibrium curve after methanol injection is the leftmost curve. There isa paucity of data in the literature as to what happens to the hydrate onboth the molecular and the macroscopic level after the addition ofmethanol. The following analysis of the process is a hypothesis basedon general experience with hydrates over the years at SINTEF.Starting with hydrate at thermal equilibrium (no temperature gradients),mechanical equilibrium (no pressure gradients) and thermodynamicequilibrium (no chemical potential gradients) at point A on figure 3,there are severa options for the behaviour of the hydrate phase afterinjection of methanol. f the pressure is kept constant, a processdescribed by line A-B is most likely to happen.Provided that a constant rate of methanol is supplied to keep the localconcentration constant, the temperature on the interface betweenhydrate and the inhibited phases is equal to TB he equilibriumtemperature is then below the ambient temperature, and the dissociationprocess will be controlled by the heat transfer to the hydrate phase.If, however, only a single batch of methanol is injected, and the pressureis kept constant, the hydrate interface will initially have a newequilibrium condition given by point B The temperature of the hydratenear the interface with the surrounding medium will decrease frompoint A towards point B. The methanol will be hydrogen-bonded towater molecules coming out of the hydrate phase, and will therefore bediluted in the inhibited fluid phases. The inhibiting effect of the injectedmethanol will diminish, and the inhibited hydrate equilibrium curve willstart to move towards the original hydrate equilibrium curve. f enoughhydrates are present, the two curves will merge into one in point A(theoretically, with an infinitesimal difference due to an infinite dilutionof methanol in the aqueous phase). Thermal and thermodynamicequilibrium will be obtained, and the dissociation process will stop. Themain difference between the two states in point A, before and aftermethanol injection, is that some of the hydrate phase has beendissociated. This may, or may not, be enough to e.g. regain partial flowin a plugged pipe.On the other hand, if the presslire is not kept constant in the case withbatch-addition of methanol (i .e. constant volume conditions), a processdescribed by the curved line A-C is most likely to happen. Theequilibrium temperature on the interface between hydrate and the fluidphases (point B) will immediately after methanol injection be lower thanthe ambient temperature, and the temperature of the hydrate phase willstart to decrease. The hydrate phase will start to dissociate. The pressurewill increase because water and gas are produced from the hydrate, andas described above, the inhibited hydrate eqUilibrium curve will start tomove towards the original (uninhibited) hydrate equilibrium curve. Atsome point, the pressure and temperature development (along curve AC) will meet the inhibited hydrate eqUilibrium curve, and the hydrate


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~ ~ I ~Figure 2

Ta TemperatureHydrate dissociation by temperature increase.Ta is the ambient temperature.

phase will be at thermodynamic eqUilibrium, but because the hydratephase is not at thermal equilibrium with its surroundings, more hydratewill dissociate until all phases are at thermal and thermodynamicequilibrium at point C. The dissociation process will stop, and the maindifference between the two states before (point A) and after methanolinjection (point C) is that some hydrate has been dissociated and thepressure has been increased.HAZARDOUS SITUATIONS DURING HYDRATE PLUG REMOVALOne aspect of hydrate plug melting by pressure reduction which needsspecial attention, is that the heat which is most readily available is theone coming in through the pipe walls from the surrounding medium(sand, water etc.). This means that the part of the plug which melts first,is the outermost layer along the wall. This is the part that is keeping theplug in place. f there is a large pressure difference across the plug,there is a possibility that it will be shot through the pipe like a projectilewhen it comes loose from the wall. This is a possible explanation for anumber of accidents in connection with hydrate plug removal. Often,the pressure has been reduced on one side only (down to atmosphericpressure), and the plugs have come loose and caused large amounts ofmaterial damage and even fatalities (Kent and Coolen, 1991).A hydrate plug in a pipeline will have a porosity depending on the fluidsystem. In general, a gas system will produce low porosity plugs, whilean oil system will result in higher porosity because of inclusion of w aterand oil droplets. During the melting of porous plugs, the melting rate inthe plug interior might be of the same order as the rate along the wall.This results in a slushy, grainy snow-like mass, which has less potentialfor damage if the plug comes loose. f the pressure on one side isreduced to a level where the corresponding hydrate equilibriumtemperature is below O C, the water produced in the pores will freeze.This process will release heat, and the temperature of the plug is notlikely to drop below OC. The ice may close the pores in the plug, andeventually stop the propagation of the pressure reduction. The meltingwill then take place mainly along the wall. A wedge-shaped meltingzone will move along the plug-wall interface, reduCing the contact areabetween plug and pipe wall. At some point this contact area will becometoo small to hold the plug, which may be shot through the pipe withhigh kinetic energy, damaging pipe and equipment.One way of avoiding this is to depressurize both sides of the plug if atall possible. The plug will then be stationary, and the melting processwill be both safer and quicker. Lowering the pressure such that theequilibrium hydrate temperature is below O C should be avoided. Iceformation will prolong the melting process substantially. This sets abound for the attainable melting rate, as generally only a relatively smalltemperature difference in relation to the surroundings can be obtained

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b ~ -- I ~Figure 3

Ta TemperatureHydrate dissociation by methanolinjection. Ta is the ambient temperature.

at sea bottom conditions. During two-sided depressurization it might beadvantageous to retain a small pressure difference, to be able to detectthe melting of the final blockages.It is also possible to combine pressure reduction with inhibitor injection.Several advantages are obtained with this powerful hydrate plug removal

D e t ~ o d . First of all, if. an inhibitor is injected upstream the hydrate plug,It WIll be transported mto the porous plug when the pressure is reduceddownstream. Water produced into the pores of the plug will then beinhibited and may not be able to form ice, and the porosity of thehydrate plug will increase continuously. If an inhibitor like methanol isapplied, the dissociation rate will increase even more; with much lowerprobability of hazardous situations.Temperature increase is not generally an applicable method for removalof hydrate plugs in subsea pipelines, but a short look at hazardoussituations caused by the temperature increase method in processequipment might be useful.A common way of removing hydrate plugs in process equipment (pipes,valves, scrubbers, separators etc.) is heating the plugged unit with hotwater or steam. This is a very effective way, but caution is required.When the ambient temperature is increased beyond the hydrateequilibrium temperature for the given pressure, the hydrate starts todissociate, and produced gas and water will raise the pressure. Apressure-temperature development described by curve B-D in Figure 2will occur. This means that as long as there is hydrate left to dissociate,and the fluids are not able to escape, the pressure will increase to theeqUilibrium pressure corresponding to the temperature of the hot water,which normally is at a dangerous level. In laboratories at the universityof Moscow, pressures of several thousand bar have supposedly beenproduced in this way (Makogon, 1994). Catastrophic rupture of processequipment may occur.The heat added will first dissociate the hydrate closest to the pipe wall. Ifthis process takes place along the whole plug - which can easily happenfor short plugs in process equipment - the plug may come loose fromthe pipe wall and may again be shot through the pipe as a projectile, ifcare is not taken to equalize pressures upstream and downstream.Injection of methanol is a common way of dissociating hydrate plugs inthe North Sea, usually in combination with pressure reduction.Inhibitors used in combination with pressure reduction will reduce therisk of developing hazardous situations. No hazardous situationsconnected to hydrate plug dissociation have yet been attributed toinhibitor injection alone.


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INQUIRY RESULTSAll petroleum companies active in Norwegian continental waters weresent a questionnaire regarding hydrate problems in pipelines.Experience from the previous inquiry (Johnsen, 1990) indicated thatvery detailed questions on pipe diameter, length, fluid composition,pressure and temperature conditions etc. were needed to analyze thereports. In addition, questions on production history leading up to theproblems, estimates of hydrate amounts, removal procedures andgeneral company procedures, awareness and experience transfer wereincluded. A full report on the inquiry is found in Lysne et al. (1994).The relatively low number of reported incidents (three companies) mustbe seen in relation to the short period of only three years. A total of sixincidents of hydrate problems in pipeline transport were reported in theearlier study (Johnsen, 1990).The received data were mostly adequate to fulfil the main goals of thisstudy; to chart incidents and company procedures and awareness. Theanswers vary from short denials of any problems, to hundreds of pagesof documentation of pressure and temperature conditions, detailedpipeline profiles, etc. A summary appears in Table 1.More than half the companies (8) report no problems with hydrateformation in pipelines. Some of them indicate extensive research effortsresulting in procedures and knowledge used to avoid possible problems,while others describe the need for hydrate awareness as small, and relyon e.g. warmer climates to avoid problems.

Table 1 Summary of received questionnaire answersCompany Problems Type Solution Experience(NS: North transferSea)

1 No - - NlA2 Yes onshore MeOH+ No formalplugs depres-surization3 No - - N/A4 No - - Special

workdescriptions5 Yes subsea Inhibitor + Noneplugs depres-surization6 No - - N/A7 Yes (NS) subsea MeOH+ Noneplugs Alcohol8 Yes (NS) subsea MeOH, heat Extensiveplugs and coursedepres-surization package9 Yes onshore Heat + Publicationplugs depres- ofsurization experience10 Yes subsea and Inhibitor + Coursesonshore depres-plugs surization11 No - - NlA12 Yes (NS) subsea MeOH+ N/Aplugs depres-surization13 No - - NlA14 No - - None15 No - - Yes

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A group of four companies describe hydrate problems and incidentsfrom other geographical locations than the North Sea. On-shore gaspipelines with diameters from 3 to 12 and lengths of 8 km to 80 kmare described as having hydrate problems when ambient temperatureshave been low. One company reports problems with a 3 , 4.5 kmsubsea gas pipeline in a more southern climate. A common feature ofthe reported incidents from another company is that their onshore lineshad been shut down at low temperatures and high pressures, andproblems occurred at start-up. Wet gas lines, of different lengths,diameters of 2 to 19 , and with rather bumpy profiles are reportedas having hydrate problems whenever sea temperatures are low enough.It is of special interest to note that one company sometimes uses piggingto clear hydrate slush from the pipes. This procedure is generallynot advisable at all, because of the danger of packing the hydratestogether and creating plugs.Only three of the companies discuss hydrate problems in the North Seain their reports. One describes a large-diameter gas pipeline of 350 kmlength which was completely plugged. This was due to an ice plug usedto isolate another pipe branch accidentally entering the pipe and actingas a nucleation site for hydrates. Inhibitor injection for several weekswas needed to clear the plug. Another company offers documentationof two separate plug incidents in the North Sea. One took place in a 9oil and gas pipeline of 12 km length, with a very bumpy profile. Theplugging was due to a faulty valve, letting water enter the stagnantpipeline. Pressure reduction and a large batch of methanol was used toremove the hydrates over a period of 24 hours. The other incident tookplace in a 6 , 12 km un insulated test- and service pipeline. After aninhibited shut-down, the line was restarted without the properprocedures for inhibitor injection being followed. Hydrates werelocalized close to the processing facility, and were quickly removed bymethanol injection downstream, and by spraying of hot water on theoutside of the exposed pipe. The third company discusses aspects ofhydrate formation in as , 7 km flat-profile oil pipeline. Temperaturedrop and unplanned shut-downs are identified as critical factors.Procedures for organizing and transferring hydrate knowledge differbetween the companies, from no procedures in one company, to anextensive package with hydrate courses specialized and adapted for allrelevant technical levels within one of the others.COMPANY PROCEDURES FOR HYDRATE CONTROL ORPREVENTIONAll companies which have hydrate activities seem to evaluate thepossibility for hydrate formation by the use of so-called handbookmethods or different advanced computer programs. The handbookmethods are usually reliable if a liquid hydrocarbon' phase(condensate/oil) is not present. The computer programs which are used,are mainly based on hydrate theory from van der Waals and Platteeuw(1959), which is known to give satisfactory results for most engineeringpurposes.Glycols (usually monoethylene glycol) are most often used forcontinuous hydrate inhibition. These chemicals also often behave ascorrosion inhibitors. Methanol is used or going to be used by about halfof the companies which need inhibitors. The same chemicals are used atshut-down or start-up.The methods used for calculation of the total amount of inhibitorsneeded, have only, been given by one company, which has developed amultiphase computer program handling the inhibitor distribution in allphases. Many computer programs in use only give the amount ofinhibitors needed for the water phase, ignoring inhibitor distribution togas and liquid hydrocarbon phases. The additional amount of inhibitorsneeded has to be evaluated from tables or experimental data. Thereceived answers do not indicate whether or not this is done.Four of the 15 companies have described formal procedures fortreatment of hydrate problems. Other companies seem to make fieldspecific proc,edure s as needed. .The usual ways to treat hydrate problems an a pipeline seem to be;for a partly clogged pipeline, methanol is injected upstream thehydrates.for a completely clogged pipeline, depressurization is used prior tomethanol or glycol injection.


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Table 2 Range of system characteristics for reportedhydrate problems in pipeline transport.Pipeline Characteris tic Extreme values reported

Pipeline length 5 - 350 kmPipe inner diameter 2 - 30Insulation From none, to both coating andtrenchingFluids Gas system - oil systemPipeline profile From flat, to extremely buckled

DISCUSSIONOne interesting trend to note, is that companies having experiencedsevere hydrate problems, seem generally much more aware of the risksin later operations, and have better procedures ready in case of reoccurrences. From the information. received, it is clear that problems ofhydrate formation in pipelines are not restricted to special cases, specialfluids or special pipe characteristics. Table 2 shows the range ofdifferent characteristics which were reported for problematic pipelines.The clearest indication of beginning hydrate problems for a pipeline inoperation seems to be an increasing pressure drop. It is important thatoperators learn to recognize this sign, in addition to knowing thehydrate-favouring pressure and temperature conditions. f the hydratesare identified at an early stage, inhibitor injection or production rateincrease may be enough to remove them before a hydrate plug isdeveloped.Start-up of pipelines after long shut-downs where fluids have reachedambient sea temperature, is one of the major trouble areas. To start theflow, the line, has to be, pressurized, and temperature and pressureconditions will often be well inside the hydrate stability region. It isimportant to try and inhibit the fluids before such a shut-in, and alsobefore the start-up is performed - although this often presents practicalproblems.Pressure reduction and methanol injection are clearly the most favouredmethods of removing hydrates once they have formed. A method whichis not often possible to use on transport pipelines (especially subseaones) but all the more usual in process facilities, is the spraying of hotwater or steam on the pipe outside to melt hydrates. All theseprocedures and their accompanying possibilities for hazardoussituations were discussed earlier.It is worth noting that most of the reported incidents of hydrates haveoccurred during normal operation (including shut -down and start-up),and are seldom due to abnormal events or pure accidents. It seemsabout 75 of hydrate problems occur during normal operation.However, this number is not entirely accurate, due to several companieslumping incidents together in their reports.In relatively short pipelines, hydrate formation conditions are usuallyonly reached in the case of low flowrate or during a shut-down. As anexample, Figure 4 shows the' temperature profile of the pipeline fromTordis to Gullfaks C in the North Sea, at different times after shut-down,from steady state simulations with the OLGA multiphase flow simulator(Lysne et al., 1992).Figure 4 shows that the temperature at the Tordis manifold and at theGullfaks C riser reaches possible hydrate formation conditions about 9hours after shut-down.For long pipelines, insulation characteristics are generally of lowimportance. The flowing fluids will fairly rapidly (especially at shutdown) reach ambient temperatures. For subsea pipelines, this is wellinside the hydrate envelope at most operation pressures. Other measureshave to be taken to avoid hydrates - mostly chemical inhibition. Onecompany reports operating in warmer climates as enough to avoidhydrate problems altogether. This is a false sense of safety, as seabottom temperatures can be low on most continental shelves. This senseof security should also vanish in light of reports of hydrates occurring

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(c)60

50

40

30

20

10t. Hydrate temperature

o ~ r ~ p15

Figure 4

4015 8015 12015(m)

Fluid temperature profiles along the Tordis-Gullfaks Cflowline as a function of shut-down time(Lysne et aI., 1992).

in subsea pipelines in the Mexican Gulf, the Mediterranean and thePersian, Gulf.CONCLUSIONSThe reported occurrences of hydrate formation show that the problemappears more frequently than in the previous study, even if the laststudy was undertaken for a relatively short period of time. The twostudies together make it clear that it is also important that awareness ofpotential risk during removal of hydrate plugs is recognized. Aminority of the companies state that they have formal procedures inplace for hydrate removal. The general knowledge about hydrate andhydrate related problems vary widely in the different companies, andhopefully this is an area for improvement in the future.It has been found that hydrate problems occur for a wide variety of pipelengths, diameters, profiles, insulation characteristics and fluids. Mostproblems occur during normal operation.

REFERENCESJohnsen H.K. (1990). Kartleggin g av hydratproblemer ipetroleumsvirksomheten , Report for the Norwegian PetroleumDirectorate (in Norwegian).Kent, R.P., Coolen, M.E. (1991). Hydrates in Natural Gas Lines ,paper presented at Mobil safety conference.Lysne D., Sa:ther G., Lund A. (1992). Evaluation of potential hydrateproblems for Tordis field development , Multiphase Transportationill - Present Application & Future Trends, conference at Rf/lros Norway.Lysne D., Larsen R., Lund A. (1994). Hydrate problems in pipelines -An inquiry among petroleum companies with operational responsibilityon the Norwegian continental shelf, 1991-93 , report. no.STFI IF94008, SINTEF, Trondheim, Norway


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Lysne D. (1995). Hydrate plug dissociation by pressure reduction ,Dr.ing. thesis, Norwegian Institute o Technology (NTH), preprint.Makogon Y. F. (1994). Russ ia's Contribution to the Study o GasHydrates , Ann. N Y Acad Sciences Vol 715 pp 119-145, New York.Sloan E. D. (1990). Clathrate Hydrates o Natural Gases , MarcelDekker Inc., New York.van der Waals, J. H., Platteeuw, J. C (1959). Clathrate Solutions , Adv.Chem Phys 2 pp 1-57.

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hydrate problems in pipelines

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