Slug Paper

8/19/2019 Slug Paper

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Background

Slug flow can pose serious problems to the designer and operator of two-phase flowsystems. Large and fluctuating rates of gas and liquid can severely reduce the production

and in the worst case shut down or damage topside equipment like separator vessels and

compressors. As a result, prediction of slug characteristics is essential for the optimal,efficient and safe and economical feasible design and operation of two-phase gas-liquid

slug flow systems.

Abbreviations

Word Explanation

1 Slug A slug consists of a gas pocket and a liquid slug

2 Terrain slug Long slug caused by a dip in the flowline

!ydrodyna"ic slug Slug caused by hydrodyna"ic instabilities

# Se$ere slugging %sually used for terrain and riser&induced slugging

' (L)A Transient "ultiphase flow si"ulator de$eloped by *+E andScandpower

, Transient +low Ti"e&dependent +low

Slugging caused by operations

1 Slugging caused by pigging-igs are run through pipelines for a $ariety of reasons including. liquid in$entorycontrol/ "aintenance and data logging/ pipeline cleaning and de&waxing/ andinhibitor application0 aker and c3onald de$eloped a quasi&transient "odel forpigging in which the lengths and pressure drops were esti"ated and tracked withti"e0 Se$eral in$estigators ha$e "odified the "odel/ and these are againincluded in the co""ercial steady state flow progra"s0 The transient si"ulators"odel the physics of pigging "ore rigorously and accurate than the steady statesi"ulators0 The si"pler "odels/ howe$er/ gi$e pretty good predictions0

To esti"ate the slug $olu"e by hand/ the designer can use the "ethodpresented here0 The pig and the slug in front of it "o$e at a $elocity that is equalto the gas $elocity behind the pig0 When the liquid exits the line/ the $olu"e ofliquid ahead of the pig is equal to the liquid holdup in the line "inus the a"ountof leakage past the pig "inus the a"ount of liquid produced while the pig istra$ersing the pipeline0


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2 Slugging at startup and blow-downWhen a line is shut down/ the liquid will drain to the low points in the line/ andwhen the line is restarted/ this liquid "ay exit the line in the for" of slugs0 Slugs"ay also for" during depressuri4ation due to high gas $elocities0 Transient

si"ulations can be used to esti"ate both of these types of slugs0

3 Slugging produced by transient effects*n addition to the "echanis"s already discussed/ slugs "ay be produced as aresult of transient effects such as pressure or flow rate changes0 +or exa"ple/ ifa line operating in stratified flow is sub5ected to an increase in gas flow rate ortotal production rate/ one or "ore slugs "ay be produced as the equilibriu" le$eldrops towards a new steady state condition0 A transient "ultiphase flow progra""ust be used to esti"ate such transient effects0

Problems related to slugging

Problems that can be caused by slugging are!. Liquid overflow, separator

". #igh pressure, separator

$. %verload on gas compressors&. 'upture due to sudden opening of valves (waterhammer)

*. Pigging

+. atigue caused by repeating impact

. #igh frictional pressure drop for hydrodynamic slugging. /nd of production when low flow rates

0. Production slop due to high static pressure changes due to long slugs.

1hese are treated below.

1 Liquid overflow

Liquid overflow in the separators can be a serious problem. 1he liquid level rises faster

than the separator can purge the liquid. 1he problem is connected to large-diameter, low

velocity pipelines.

2 Hig pressure

#igh pressure in the separator or near the outlet can be a serious safety problem. Large

amounts of gas can give high pressure in a small vessel2separator, and shutdown due tooverpressure.

! "verload on gas compressors


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3ownstream components, like a compressor, might require steady gas flow rate. Slug

flow typically gives an oscillating gas flow rate, with very high rates at times. 1his is the

main reason for shutdown on 4allhall where the gas compressors need a relatively steadyinflow of gas.

# Large pressure impacts

Slugs can create large pressure impacts, especially passing through valves or bends. 5f theorifice is half the pipe-area, the slugs can cause pressure fifteen times higher than the tank

pressure. 1his can eventually lead to rupture.

Special care must be taken during start-up since liquid can be stored in the dips of the pipeline. 3uring start-up these liquid plugs will be blown towards the outlet and can

cause severe damage to the process equipment.

$ Pigging problemsA pig sweeps liquid in front, and can bring large amounts of liquid into the slug catcher

or separator, depending on the pipeline geometry and the pig velocity.

% &atigue

6echanical fatigue is another problem. 'epetitive slugs can cause mechanical failure at a

significantly lower impact than the ma7imum mechanical load 89. Slug-loading data

coupled with S-: curves can determine fatigue life.

' Hig frictional pressure loss1he slug flow regime (hydrodynamic) has a high frictional pressure loss compared to the

other flow regimes. 1hus, a change in flow regime in long flow lines might giveincreased flow capacity. :ote, however, that hydrodynamic slugging in a flowline or riser

might reduce the danger of severe slugging.

( )nd of production wen low flow rates

At the end of the field life the production rates often go down. Since terrain slugging is

more likely to occur for low flow rates, slugging is especially a problem at the end of the

lifetime of a production system. An e7ample is the /kofisk line.

Slug penomena

When liquid and gas are flowing together in a pipeline/ the liquid can for" slugsthat are di$ided by gas pockets0 The for"ation of liquid slugs can be caused by a$ariety of "echanis"s.


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10 !ydrodyna"ic effects 6surface wa$es720 Terrain effects 6dip in pipe layout70 -igging#0 Startup and blow&down'0 +low rate or pressure changes

!ydrodyna"ic slugs/ in hori4ontal and near hori4ontal pipes/ are for"ed bywa$es growing on the liquid surface for a height sufficient to co"pletely fill thepipe0 *n $ertical pipes the hydrodyna"ic slugs are ascociated with Taylorbubbles0 The hydrodyna"ic slugging is difficult to pre$ent since it occurs o$er awide range of flow conditions0 The repeating i"pacts of hydrodyna"ic sluggingcan cause fatigue0 *t can therefore be useful to predict the slug $olu"e/ $elocity/and frequency of such slugs0 +urther"ore/ se$eral hydrodyna"ic slugs cangather together due to terrain effects/ creating larger slugs0

Terrain slugging is typically created near a dip in a flowline/ well/ or riser/ and can

in principle only occur if there is downward flow0 +or purely riser&inducedslugging/ the liquid does not "o$e until gas pressure behind the blockage buildsup high enough to push the liquid out of the low spot as a slug0 Large flow ratesinitiated by se$ere slugs can cause "a5or proble"s for topside equip"ent likeseparator $essels and co"pressors0 %nderstanding and controlling thepheno"ena "ight pre$ent shutdowns and lost production0

*nitially/ hydrodyna"ic slugs are relati$ely short/ howe$er/ the slugs can gathertogether to for" longer slugs/ and terrain slugs can be hundreds of "eters long03uring the life span of a pipeline riser&pipe syste"/ both hydrodyna"ic slugs andterrain slugs can be present0 %sually/ in the early and the large stages of

production/ terrain slugging would be expected because of low flow rates/ whilenor"al slug flow would be expected for the rest of the ti"e0

(ther types of slugging are initiated by pipeline operations0 -igging of a pipelinecauses "ost of the liquid in$entory to be pushed fro" the line as a liquid slugahead of the pig0 Shut down of a line will drain the liquid that is left in the linedown to the low points0 3uring restart the accu"ulated liquid can exit the pipelineas a slug0 Also/ increasing or decreasing the flow rate of either gas or liquid leadsto a change in liquid holdup0 This can co"e out in the for" of a slug/ dependingon the flow rate0

Hydrodynamic slugging


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+igure 1. Sche"atic $iew of a slug syste" with gas pocket/ liquid slug/ and totalslug unit0

)as and liquid flowing slowly in a hori4ontal pipe will flow in a stratified pattern0*ncreasing the flow rates/ wa$es will be created/ and the liquid "ight touch thetop of the pipe creating liquid slugs separated by gas pockets 6+igure 170 The gascan also be dispersed as bubbles0 *n $ertical flow the liquid can flow like a thinannular fil" on the pipe wall0 3ifferent flow patterns occur for different flow ratesof gas and liquid/ depending on the density/ the pipe inclination/ the dia"eter/

and the pressure0 +low&pattern "aps are treated in the Flow regime map section0

!ydrodyna"ic or nor"al slug flow occurs at "oderate gas and liquid flow rates/and hence is co""only encountered in "ultiphase pipelines0 !ydrodyna"icslug&flow is characteri4ed by a series of Taylor bubbles 6gas pockets7 separatedby liquid slugs as shown in +igure 10 *n upward flow/ the Taylor bubbles aresy"etrical0

The a$erage slug length is a co"plex function of "any $ariables. the dia"eterand length of the pipeline/ the topography of the line/ the gas and liquid

$elocities/ the liquid physical properties/ and the gas density0 !ere we willdiscuss the pheno"ena0 See the Slug-length "odel section for "odelreco""endations0

A rule of thu"b says that the slug length is equal to 2 ti"es the pipe dia"eter 3819:0 This is the "ini"u" stable slug length0 Experi"ental work 819: found sluglengths between 12 to 9 ti"es the pipe dia"eter/ and showed how the sluglength decreased with superficial air $elocity and pressure0 3ukler found sluglength to be 29 ti"es the pipe dia"eter0

)eo"etrical effects can "ake the slugs grow or disappear0 ost of the

correlations for slug flow are based solely on laboratory data/ which "eans theyare of li"ited use in design of pipelines in the field0 A few correlation "ethods arebased on field data0 Two of those/ the rill et al0 correlation and the !ill andWood "ethod/ ha$e been widely used for slug length predictions0 The rillcorrelation gi$es a slug length of about 99&'9 ti"es the pipe dia"eter0

Experi"ents ha$e shown that the "axi"u" slug length depends on where in theslug regi"e the flow is0 ;ear the elongated bubble transition the "axi"u" slug


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lengths are ca0 2 ti"es the "ean/ while it is #&' ti"es the "ean near the stratifiedwa$y boundary0

The slug $elocity can be calculated fro" gas and liquid flow rates if the $oidfraction is known which is usually not the case0 !owe$er/ in a hori4ontal line the

"ean $elocity of the liquid in the body of the slug is approxi"ately equal to the"ixture $elocity/ see Slug-load "odel section for calculation details/ while nearthe outlet 6separator7 the slug $elocity can $ary significantly/ and the $ariationsincrease with decreasing slug length0

The $oid content of the liquid slug 6+igure 17 can be as high as 90' $olu"efraction down to 9010 There are a nu"ber of approxi"ate correlations for theliquid hold&up in slugs0 So"e of these are presented in the Slug-load "odelsection/ but none of these are accurate/ and this is still an area of research0

The slug $oid 6$olu"e7 fraction or a"ount of gas in the liquid slug increases

appreciably with the gas density 821:0 Also the liquid $iscosity is i"portant0 (ilslugs will usually contain "ore gas than water slugs0 An exception is low $elocityflow in large dia"eter pipes 63


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1he severe slugging cycle is characteri?ed by a noticeable period of constant liquid

production followed by a large transient as the liquid column is blown out. 'equirementfor e7istence is that the liquid penetrates into the pipeline.

1he transitional severe slugging includes 1ype ; and 1ype ell instability will give varying inlet rates in the riser, and this can resemble severe

slugging.

1he three slug phenomena were also described by 1aitel (!00+) who draw the flow map

in igure ". 1he map displays for which flow rates there can be instabilities in a riser withwater and air at near atmospheric conditions. 1he lines A to 3 represent the flow rate-

limits (superficial velocities) for the instability phenomena. 'iser instability can occur to

the left and below the lines A to 3B or more precisely to the left of Line A, below Line ;,

left of Line


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igure " %ccurrence of severe slugging in an air-water system at "*


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+igure 0 Terrain&induced slugging0

Terrain&induced slugging and riser&induced slugging are both classified as se$ere slugging/ andcharacteri4ed by liquid accu"ulation at low points0 The gas upstrea" is co"pressed until ito$erco"es the gra$itational head of the liquid/ thereby creating a long liquid slug that is pushed infront of the expanding gas upstrea"0

To obtain terrain slugging/ the flow "ust be stratified in a downward inclined pipe before a lowpoint0 This is because the slug pheno"enon is dependent on a large/ co"pressible $olu"e0

+urther/ the pipeline "ust ha$e downward flow at so"e location0 *t is also worth noticing thatterrain slugging occurs for relati$ely low liquid and gas flow rates 81>/1=:0 ?riteria for when youwill get se$ere slugging are presented in the Criteria section0

Slug for"ation will/ on a$erage/ occur when the depth of liquid in the low point of the dip exceedsa certain critical $alue 6depending on the gas flow rate70 The frequency of se$ere slugging willalso depend on the length of the upstrea" pipeline0 *t takes a relati$ely long ti"e to co"press thegas in a long pipeline 8@:0

+or riser&induced slugging/ a rough rule says that the slug length is equal to one to three riserdepths0 !owe$er/ this is probably not correct for deep water down to 2999 "eter0 See the Sluglength "odel section for "odel reco""endations0

3uring production the length and $elocity of a slug can be esti"ated by "onitoring the pressure$ariation at the outlet of the pipeline 82:0 easure"ents ha$e shown that the flow $elocities $arysignificantly during se$ere slugging/ yet/ the $elocity follows a sy""etrical nor"al distribution 8@:0

The $oid fraction of a terrain slug can be $ery low and "uch lower than for hydrodyna"icslugging due to the different "echanis"s creating the two types of slugging0 *0e0 assu"e 4ero$oid fraction for design purpose0


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*n a riser/ the slug will decelerate as the line upstrea" of the slug packs up to pro$ide thepressure to o$erco"e the increasing hydrostatic head in the riser0 As the slug lea$es the riser thehydrostatic head loss in the riser reduces so that the upstrea" gas bubble expands andaccelerates the slug into the separator0

+igure # presents the $olu"e flow at the outlet of a riser0 There is no liquid f low while the slug is

generated0 +igure ' shows the pressure for the sa"e case0 The pressure builds up during sluggeneration/ and goes down during bubble penetration0 The last peak is caused by the gas insolution0 o$ing towards lower pressure/ gas co"es out of solution and gi$es a lift effect0 erticalforces on a bend are shown in +igure ,0 These forces are large during bubble penetration0

+igure #. Liquid $olu"e produced and gas&flow rate during a se$ere slug cycle for a full&scalepipeline riser&pipe syste" 81>:0

+igure '. A$erage pipeline pressure during a se$ere slug flow cycle for a full&scale pipeline riser&pipe syste" 81>:0


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+igure ,. -ressure and force on a bend caused by se$ere slugging 8@:0

Procedure for slug prediction

!. Secure information on pipe profile, fluid (density, F%', etc.), and production profile(Pressure, flow rates, temperature). See Slug criteria and Slug growt further down for

terrain slugging e7plains and the importance of pipe profile.

". 3efine system boundaries for analysis, definition of problems and selection of problemsolutions. or e7ample is it important to determine whether the wells and the near well

inflow must be included to understand the behavior of the system.

$. ind if there is both gas and liquid at operating conditions. 5f there is no gas anywhere

in the pipe, there is (off course) no gas-liquid slug.

&. /7plore the flow regimes at different locations and instances in the pipe and production profile. 1his can be done using &low,regime maps. 'emember that it is required to have

stratified flow upstream the riser to get severe slugging in the riser.

*. atch therefore also up for hydrodynamic slug flow using the &low regime map tool.

+.


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.


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+igure >. Biser&pipe flow pattern "ap for a downward pipeline inclination of 2percent/ and with analytical predicted boundaries0 Superficial gas and liquid$elocities were "easured at separator condition of 10= bar 81>:0

Stratified flow

Severe slugging will (usually) only occur if there is stratified flow in a downward section ust upstream of an upward section or riser. 1his criterion should be checked using a

flow-regime map.

:otice that hydrodynamic slugging in the downward section prevents riser-induced

slugging since it is caused by gas compression before the riser. #ydrodynamic slugs havesmall continuous gas volumes. 1his prevents the buildup of terrain slugs.

Slug growt

Several criteria for slug growth in a riser have been developed. 1hey are based on

balancing the gravitational forces against the pressure in the bottom and top part of ariser.

1he criteria of ;@ is the simplest, and a very conservative criteria saying that slugging

can occur if


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)quation 1

GLS and GFS represent superficial liquid and gas velocities, Pp is the upstream pressure,alpha is the average upstream void fraction (in the stratified part), L is the length of the

pipe, and beta is the inclination angle of the upward riser. 1his criterion is usually very

conservative, and should be used as a first check. ;e aware that the system does notnecessarily slug although the ;@ criterion is satisfied.

uchs 8"9 developed a more refined criterion. Like ;@ he uses the pressure balance over

the riser in his analysis, but then he differentiate this. #is analysis shows that the slugging

tendency of pipeline-riser systems is in general governed by a non-dimensional terrain-slugging parameter that combines the pressure with the relevant system and fluid

properties. As the pressure increases, the terrain slugging region in the flow map shrinks

and the slugging mechanism changes.

1he criterion of uchs for slug growth says that terrain slugging can occur if

)quation 2

where

terrain slugging parameter

pressure upstream

pressure downstream

volume gas upstream

volume gas downstream

riser-pipe cross section

riser angle to the hori?ontal

density gas


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liquid hold-up in slug

liquid hold-up in riser entrance section

superficial gas velocity at riser base

superficial liquid velocity at riser base

superficial gas velocity in feed stream

superficial liquid velocity in feed stream

1his criterion is less conservative, but require more input parameters than the ;@criterion. 5t should be tested when the ;@ criterion predicts possible slugging. %ther

criteria, like the one developed by 1aitel, are more conservative than the one of uchs, but less than the ;@ criterion, and can also be used as a check.

-nstable flow

Slugging can occur due to unsteady flow in a riser, well or similar. 1hen, an increase in

gas flow-rate results in an increase in pressure. 1his is the case if the system pressure-loss

becomes dominated by hydrostatic head loss, rather than by friction. 1his is usually thecase for the non-choked pipeline-riser. 5n order to establish a stable, friction-dominated

system, a choke near the top of the riser can provide a pressure drop comparable to the

hydrostatic head loss over the riser when full of liquid.

igure Stable and unstable regions of well performance with and without choke.


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Producing wells need sufficient reservoir pressure in order to produce with liquid in the

upward section. 1he well-performance relationship (pressure plotted as a function of flow

rate) has an unstable region for low flow rates and a stable region for high flow rates. 1hewell performance is the solid line in igure . rom the shape of this well-performance

curve, we see that two different pressures can give the same wellhead pressure. 1he high

flow rate implies steady flow, while a low flow rate will give an unsteady solution with pressure diverging away from the original solution. 1his can result in slugging or a dying

well. A wellhead choke will alter the well performance such that the unstable region gets

smaller as shown by the dashed line in igure .

1he limit for unstable flow can be found calculating the gas flow rate corresponding to

the minimum pressure drop for different liquid flow rates (including the choke). An

e7pression or correlation for the pressure drop is needed. 5n general the well is stable if,

8&9

)quation !

.o annular flow

1he 1aitel-3ukler-;arnea criterion for the onset of annular flow provides a good estimate

of the quantity of gas required eliminating severe slugging. 1his criterion can be used for

gas-lift calculation. 1he method predicts that the transition from annular flow occurs atsuperficial velocities in e7cess of a critical value given by

)quation #

>here is the surface tension, g is the gravity, F and L are the gas and liquid densities.

Slug lengts

This guideline gi$es reco""endations for how to predict the slug length of slugscreated by

• !ydrodyna"ic effects

• Terrain


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This gi$es a slug length of LsC99&'9 ti"es the pipe dia"eter0 The for"ula isbased on field tests at -rudhoe ay +ield with pipes with inner dia"eter 3C2#Dco"bined with lab tests0 The abo$e slug&length correlation has beco"e theindustry standard design "ethod/ and has been used extensi$ely by oilco"panies and contractors since 1=>=0

Maximum slug length and statistical variations are i"portant para"eters0 %singthe li"ited -% data/ rill et al0 had concluded that slug lengths followed alognor"al distribution0 !ence the rill correlation always calculates the "axi"u"slug length to be #0> ti"es the "ean0 !owe$er/ near the elongated bubbletransition "axi"u" slug lengths are only ca0 2 ti"es the "ean while it is #&'ti"es the "ean near the stratified wa$y boundary0 A distribution that has shownto be good is the lambda distribution with a power of 90@0

Riser-induced slugs are usually between one to three ti"es the riser depth0!owe$er/ this "ight not be the case for $ery deep water down to 2999 "eter/ nor

for wells0

The a$ailable design "ethods for slug pheno"ena are known to significantlyo$er&predict the slug si4e0 A "echanistic "odel or a transient progra" can beused in the "ore detailed design phase0

Pigging can be esti"ated by co""ercial a$ailable progra"s/ like (lga0 Toesti"ate the slug $olu"e by hand/ the designer can use the following "ethod0The pig and the slug in front of it "o$e at a $elocity that is equal to the gas$elocity behind the pig0 +or a first approxi"ation/ this $elocity can be assu"ed tobe equal to the "ixture $elocity0 The export ti"e of the pig would therefore be.

where ttrans is the transit ti"e for the pig/ L is the pipeline length/ and is thea$erage "ixture $elocity0 This assu"es that the pigging is perfor"ed during

production0 The $alue for when the flow is stoped is an unknown that "ust begi$en an appropriate $alue0

When the liquid exits the line/ the $olu"e of liquid ahead of the pig is equal to theliquid holdup in the line "inus the a"ount of leakage past the pig "inus the

a"ount of liquid produced while the pig is tra$ersing the pipeline or.

/!uation $

resulting in a liquid slug length LSCslugA0 The $alue of fleak is dependent onthe type of pig and the pig $elocity0 *n lack of better data use fleakC90920


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Start-up and transient slugging can be found using a transient progra"0 utfirst/ study whether such slugging can occur0

OLGA slug tracking "odel reproduces slug length distributions si"ilar to thoseobtained in field "easure"ents 81':/ howe$er so"ewhat shorter 8@:0 The

"ultiphase flow si"ulator (L)A can also be used to predict hydrodyna"ic slugs/but gi$es too s"all slug length/ or about #9 F s"aller than real0 %se flow&regi"e"ap and stability criteria to study whether the case is slugging before running(lga0

Slug frequency and slug loads

This section shows alternati$e "odels for slug frequency both

•

for hydrodyna"ic slugging/ and • in real flowlines in the terrain

For hydrodynamic slugging there are se$eral for"ulas for the frequency0 The(L)A "anual 82: gi$es a for"ula by Shea for predicting the slug frequency.

!uation %

where L C slug unit length/ 3 is the inner dia"eter/ and %SL is the superficialliquid $elocity0 This for"ula is deri$ed for slug generation in straight pipelines0

In real flowlines in the terrain the slug frequency is also dependent on thegeo"etry and slug growth0 T0G0 !ill and 30)0 Wood 81: presented a "ethod topredict slug frequency0 This "odel is applicable to near hori4ontal syste"s0 Theresulting Dbest&fitD a$erage slug frequency equation/ equation 67/ wasdeter"ined using a double exponential bounded approach0 This pro$ed to be the"ost suitable of a nu"ber of equation&for"s in$estigated on the co"bination ofdifferent data sets0 This "ethod should also be used in the !ill and Wood slug&

length esti"ate0


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!uation &

where

. equilibriu" stratified liquid&holdup

!uation 1'

Habaras 8': exa"ined $arious "ethods proposed in the literature for predictingthe slugging frequency in hori4ontal and inclined pipes0 These included bothe"pirical correlations as well as "echanistic "odels0 A total of eight published"ethods were co"pared to slug flow frequency data but none was foundsatisfactory0

+or this reason the "echanistic slug frequency "odel of Taitel and 3ukler 61=>>7was in$estigated in detail0 The calculations according to this "odel required thesolution of unsteady&state equations for "ass and "o"entu" by a finite

difference technique0 This nu"erical "odel ga$e satisfactory results at theexpense of co"puter ?-% ti"e0 +or faster slug frequency calculations a newcorrelation/ Equation 11/ was de$eloped using all the data points0 *t representssignificant i"pro$e"ent in slug frequency prediction accuracy o$er the other"ethods studied and is therefore reco""ended for routine slug frequencycalculations0

!uation 11

where

. superficial gas $elocity

. pipe inclination angle 6positi$e for upward inclined pipelines7


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. gra$ity constant

The Taitel and 3ukler "odel is reco""ended for calculating slug frequenciesparticularly so for flow conditions outside the a$ailable slug flow data 6i0e0dia"eter larger than @ inches/ liquid $iscosity larger than 19 cp/ etc070

Riser-induced slug frequency is extre"ely dependent on the geo"etryupstrea" of the riser0 +or"ation of terrain slugs will/ on a$erage/ occur when thedepth of liquid in the low point of the dip exceeds a certain critical $alue6depending on the gas flow rate70 The frequency of se$ere slugging will alsodepend on the length of the upstrea" pipeline0 This is shown by the I slug&growth criteria Equation 1/ which is dependent on the pipeline length0 Typicalslugging periods are so"e "inutes to se$eral hours0 *t takes a relati$ely longti"e to co"press the gas in a long pipeline 8@:0

Pigging start-up and transient slugs are caused by operations0 Thus/ the slug

frequency depends on how often the well or pipeline is exposed to start&up/pigging/ or rate changes0

OLGA slug&tracking "odel gi$es a higher slug frequency than obser$ed in"easure"ents 8@:0 ;ote also that (L)A is appropriate for near hori4ontal cases/howe$er/ in general the "odel is not as good for $ertical and de$iated wells dueto li"ited e"pirical data0

1hree parameters are important when calculating the slug load. 1hat is

•

the slug length,• the slug velocity, and

• the density or holdup of the slug.

1he two later will be discussed here.

Hydrodynamic slug !elocity can be calculated fro" gas and liquid flow rates ifthe $oid fraction is known 6which is usually not the case70 !owe$er/ in ahori4ontal line the "ean $elocity of the liquid in the body of the slug isapproxi"ately equal to the "ixture $elocity/ hence the slug $elocity is.

!uation 12

A "ore refined for"ula/ including slip and buoyancy effects/ is

!uation 13


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(ne of these two equations should be used when e$aluating the forces i"posedby a slug as it tra$els through a bend0 ;ote/ howe$er that near the outlet6separator7 the slug $elocity can $ary significantly/ and the $ariations increasewith decreasing slug length0

In a riser the slug will decelerate as the line upstrea" of the slug packs up topro$ide the pressure to o$erco"e the increasing hydrostatic head in the riser0 Asthe slug lea$es the riser the hydrostatic head loss in the riser reduces so that theupstrea" gas bubble expands and accelerates the slug into the separator0 Thiscan be "odeled in a dyna"ic progra"0

"he !oid content of a liquid slug can be as high as 90' $olu"e fraction down to9010 This has i"plications for the slug i"pact0 There are a nu"ber of approxi"atecorrelations for the liquid hold&up in hydrodyna"ic slugs0 (ne of the "ostco""on is that of )regory

!uation 1(

This for"ula can ha$e an error of about '9F0

The slug $oid fraction or a"ount of gas in the liquid slug increases appreciablywith the gas density 821:0 Also the liquid $iscosity is i"portant0 (il slugs willusually contain "ore gas than water slugs0 An exception is low $elocity flow inlarge dia"eter pipes 63


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formation of bubbles. 5f there is a gas cap over the oil, the oil in the reservoir will be near

to saturated. 5f there is no gas-cap, the oil may be highly under-saturated such that the

pressure is much higher than the bubble point pressure of the oil. Liberation of free gasmay then not occur before the oil has reached the riser. 5n this situation, there is little

chance of getting severe slugging in the riser. 1his is the case for shallow oil reservoirs in

deep water.

5f there is a gas cap present, gas production may occur from Jgas coningK in addition tothe gas dissolved and liberated from the oil. 5n this case the F%' can be up to many

thousand, while with only dissolved liberated gas (sometimes called associated gas)

F%' is normally in the range of *D-!*D SmM2SmM. #eavy oils like 1roll and 3alia hasF%' of **-D SmM2SmM.

>hen water production starts, the fraction of is reduced and as a result the volume of gas

is reduced too. >ith !DD N watercut (defined as the volume of water produced at S1P per

volume of liquid (water oil) produced at S1P). >ith !DD N watercut, and no coned gas

from a gas-cap, then only water is produced plus the small volume of gas dissolved andliberated in the water. As a rough rule of thumb, the dissolved volume of gas in water is

P2!DD SmM gas per SmM of water, with P the pressure in bara.

1he possibility of severe slugging is highly related to the gas-liquid ratio (FL') and tothe pressure P. 1he ratio FL'2P indicates volume fraction gas and liquid. >ith mainly

liquid present it is low chance of getting severe slugging, because the system will be to

stiff. >ith mainly gas it is also low chance of getting severe slugging. 1his is understoodfrom the ;oe-criterion. #owever, although severe slugging does not occur with high

volume fraction, fluctuations in holdup and2or hydrodynamic slugging may still be a

problem.

&lasing

Fas liberation (flashing) has maor effects on the severe slugging behavior during the

different cycles as described in the following 3uring the liquid build-up phase the liquid

sees constant pressure as it flows up in the riser because of constant liquid column above.

>hen the riser is filled with liquid, the liquid from the flowline continues to flow into theriser, but as this liquid is rising it does not have a constant height of liquid column above

itself. 5t sees a reducing pressure during the rising, thus flashing will occur. 1he liberated

gas bubbles soon fills the whole riser such the density of the fluid in the riser and the back-pressure will fall. 1hen the liquid in the flowline also starts to flash giving

additional gas-lift effect.

or deep risers this gaslift effect gives a rapidly increasing flowrate. 1his gives a rapid

e7pansion in the flowline such that shortly after, the reducing flowline pressure more thancounteracts the increasing gas-lift effect and the flowrate starts to drop again. #ence a

first peak in outlet flowrate occurs, as seen in the /7ample


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After this first peak, an equilibrium situation occurs with a balance between the two

effects reducing flowline pressure which gives reducing flow and increased volume

fraction of gas in the riser due to the gas liberation with reducing pressure. 1his gives afairly constant liquid rate out of the riser until the gas pocket reaches the riser bottom.

>hen this occurs, the remaining liquid in the riser is rapidly blown out giving the second

peak of the liquid blow-out phase.

:otice that a higher content of water implies less flashing.

/eometric effects

1his section discusses how slugging is influenced by

• lowline geometry

•

'iser height and shape• 3iameter

•


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• 5n the well (G-shaped or hori?ontal with dips upstream the vertical section)

• %n the mastree. :ormally the piping on the tree is vertical downwards, i.e. a

dip, ust after the production wing valve.

• 5n the flowline or pipe between the tree and the manifold

• %n the manifold piping itself. %ften the dispatcher valves (C well routing valves)

are located on high points above the manifold header (to ensure water drainageand2or to get easy access with '%4).


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large riser, but as described in the basic theory, large riser si?e can actually prevent severe

slugging (ref ;oe criterion and the P5-ss criterion) on the cost of increased pressure drop

due to high liquid holdup.

1he subect of multiphase flow in large diameter risers is not well understood with nearly

all of the available data having been collected from e7periments with diameters less thanabout " inches, and none above +- inches. or the offshore oil and gas industry, current

design procedure relies on the tenuous e7trapolation of correlations based on the resultsfrom these small diameter pipes to the larger diameter risers used in practice.

As the industry moves into deeper waters the probable departure between the predictions

of the current models and physical reality casts significant doubt on the reliability offuture designs. 1he new systems may e7perience severe operability problems, or may

even be inoperable due to slugging, stability or pressure drop considerations.

5t is reasonable to believe that large-diameter risers will give a different flow

characteristics than small ones. Professor #ewitt at 5mperial


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&low regime maps

The "ost co""only used flow&regi"e "ap was de$eloped by Taitel and 3ukler822:/ and has gas and liquid superficial $elocities at the axis0 The "ap is based

on transition laws between the flow regi"es0 *t was first deri$ed for hori4ontalflow/ and then extended to $ertical and inclined flows by arnea 81:0 The flowpattern is dependent on density/ pressure/ inclination angle/ and dia"eter inaddition to gas and liquid $elocities0

As mentioned, a flow&regi"e "ap is an excellent tool to test for hydrodyna"icslugging0 Such a "ap should also be used to see whether there is stratified flow/which again can lead to slug growth and terrain slugging0

%sing a flow&regi"e "ap/ you should also be aware of the weak points.

•

!istory effects are not included0 This "eans/ for exa"ple/ that the flow"ap will predict the sa"e flow regi"e 5ust after a bend/ dip/ or si"ilar/ asin a straight pipeline0

• 3ue to a lack of experi"ental data/ a flow&regi"e "ap is neither $eryaccurate for negati$e pipe&inclinations/ nor for positi$e inclinationsbetween 19&@' degrees0

• Transient flow regi"es are neither well understood/ nor classified0 • Transition 4ones between the flow regi"es are uncertain0 A reason for this

is that the flow patterns are usually categori4ed by $isual obser$ations0

A ;(?B? has an inhouse progra" de$eloped by orud 81: and based onthe theory of Taitel/ 3ukler/ and arnea 81/22:0 The progra" predicts the flowregi"es for different flow rates and inclination angles0


28/33


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:ote that the different slug prevention methods might only be useful to prevent one type

of slugging. or e7ample, gas lift can prevent terrain slugging, but might even induce

more hydrodynamic slugging.

An obvious alternative to slug mitigation2prevention is simply to run the pipeline with the

slugs. 1his is an easy solution if the slugs are small enough so that the separator andcompressor system can handle the varying rates and the repeating impacts, or if there is a

slug catcher. Alternatively, the slug si?es can be reduced by changing pipe topology,repeated pigging, gas lift, or by changing the flow conditions. Prevention of slugs is

another alternative.


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• 'iser base gas lift is a common technique to avoid slugging by continually lifting

liquid out of the riser, preventing the build-up of liquid and subsequent seal to the

gas flow. 1he location and geometry of the inection point is critical. 5f gasinection is made on the hori?ontal section upstream the liquid blockage, the gas

may ust flow backwards into the flowline. 1hen very high gas flowrates may be

required to prevent severe slugging (the FL' must be increased to get that a ;oe-number R !). 5t is normally better to inect gas on the vertical section downstream

the liquid blockage. 1hen the lift-gas rate must be sufficient that the liquid is

transported up the riser, but this rate is normally lower than to get a ;oe-number R!. 'iser base gaslift will normally only prevent severe slugging. #ydrodynamic

slug will ust be diluted and the massflow of liquid will be appro7imately the as

without gaslift. 5f the gas is inected through a large diameter and long pipe asmay be the case for deep risers, another type of instability may occur which is

similar to annulus heading in gas-lifted wells. %n 3alia a + J riser that could be

up to $ km long with steel catenary risers was used for gaslift to one production

riser. 1his type of annulus-riser coupling may be controlled by A;; 5ndustriIs

Active Well Control .• Faslift in the wells can also be used to prevent slugging in the flowlines and riser.

1he mechanism for slug prevention can be a) increased velocity b) 5ncreased

flowline pressure due to increased lift in the wells and c) 5ncreased FL' such thatsevere slugging can not occur according to the ;oe criterion (;oe number R !). 5f

there is a problem with Oannulus headingO instability, active control by Active

>ell


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• c) %ptimi?e the geometry of the dip. 1he detailed geometry is critical with respect

to whether severe slugging occurs. rom the ;oe-criterion model, a slow change

in inclination from downwards to upwards, should give less tendency of severeslugging than with a steep inclination change.

• ith a steep inclination change, little liquidvolume is required to block2seal against gas flow. 1hen very rapid slug control

may be required. #owever, with a gradual inclination change, the front of the gas

bubble may move very fast backwards into the flowline such that it may not be possible to reestablish gasflow into the riser.

• %ptimi?ed well production and2or well routing. Adusting the well production

rates and2or rerouting the wells from one flowline to another, may be a simple and practical solution to the problem(s).

• Pigging2sphering can be used to avoid hydrodynamic and2or severe slugging in

gas-condensate lines (very high FL', i.e. small liquid loads) by removing liquid

accumulated in the line before slugging becomes a problem.

itigation

1he following methods does not prevent slugging. 1hey can only mitigate the effects ofthe slugs e.g. by multivariable control of the main process train to avoid high level or

high load trips.

• Slug catchers should be designed to take care of a slug before it enters the process

equipment. 1his can be both topside and subsea slug catchers. 1he si?ing of slugcatchers is a subect on its own. ;ecause slug-catching equipment can be a

substantial cost item, alternative operating-scenarios should be considered.

• Sep


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1he following methods does not prevent slugging. 1hey can only mitigate the effects of

the slugs e.g. by multivariable control of the main process train to avoid high level orhigh load trips.

*eferences

Previous slugging studies.

!. ;arnea, 3. et al., Fas-liquid flow in inclined tubes low pattern transitions for

upward flow, Chem. Eng. Science, !0*, &D(!), pp!$!-!$+.". 3hulesion, #., #ustvedt. /., and 1odal, %., 6easurement and analysis of slug

characteristics in multiphase pipelinesI, 1otal and Statoil, BHR.

$. uchs, P., 1he pressure limit for terrain sluggingI, $rd international conferenceon 6ultiphase flow, ;#', !0, pp+*-!.

&. Folan, 6. and >hitson,


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low, !00&, "D($), pp.+*0-+++.

!. Paglianti, A., 1rotta, F., Andreussi, P., and :ydal, %.T., 1he effect of fluid

properties and geometry on void distribution in slug flowI, BHR.!. Schmidt, 3oty, 3utta-'oy, Severe slugging in offshore pipeline riser-pipe

systemsI, Society of Petroleum Engineers ., ebruary !0*, "-$.

!0. Schmidt, ;rill, ;eggs, /7perimental study of severe slugging in offshore pipeline U riser pipe systemsI, Society of Petroleum Engineers ., %ctober !0D,

&D-&!&.

"D. Scott, Shoham, ;rill, Prediction of slug length in hori?ontal large diameter pipes, SPE Annual California Regional !eeting , %acland,

Slug Paper

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