19 pigging

INTEC ENGINEERING, INC. DEEPSTARMULTIPHASE DESIGN GUIDELINE

H-0806.35 19-1 1-Dec-00

19.0 PIGGING

19.1 Introduction

This section of the design guide serves to provide guidance in the design and operation of pigging systems that assure hydrocarbon deliverability in an economical manner. This section covers industry status, flow assurance pigging requirements, typical systemconfigurations and operating modes, pig types and selection, basic system components and design considerations, and system operating requirements.

19.2 Industry Status

During this decade there has been a rapid expansion in exploration and field development in ever-deeper water. With this approach, the flow assurance issues that relate to pipeline hydraulics, hydrate formation and paraffin deposition have been magnified because of the longer tiebacks and colder subsea environment.

There is plenty of pigging experience available with land pipelines and shallow water developments, especially when pigging from platform to platform. However, pigging experience in deepwater is limited and has been confined mainly to the Gulf of Mexico and Brazil. A summary of some deepwater pigging experience is found in Table 19.1.

Because of the potential show stoppers associated with deepwater production, greater interest has been given to considering the deployment of pigs as an integral part of the flow assurance and pipeline maintenance program. Several operators have recentlyperformed field specific studies to determine the feasibility of pigging as the principal means to control wax. Other studies have focused on performing trade offs between dual flowline pigging and single flowline pigging using subsea pig launcher or receiver.As more fields are developed, it is envisaged that greater emphasis will be given to the subject of pigging with the result of producing more cost effective flow assurancesystems.

19.3 Pigging Requirements

From the perspective of flow assurance, pigging is required to maintain the original design integrity and flow performance of pipelines, flowlines and risers for the duration of their intended operational life. Specific requirements are as follows:

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Tabl

e19

-1:

Dee

pwat

er P

iggi

ng E

xper

ienc

eO

pera

tor/

Fiel

dLo

catio

nPi

ggin

gC

onfig

urat

ion

Lin

e Si

ze &

Len

gth

Fiel

dSt

atus

Pigg

ing

Ope

ratio

ns

Mar

iner

/Plu

toG

OM

MC

674

One

way

from

sub

sea

pig

laun

cher

(269

0 fe

et) t

o So

uth

Pass

89B

fixe

d pl

atfo

rm (3

26 fe

et)

8-in

ch s

ingl

e, 3

2 m

iles

Plan

ned

Wax

dep

ositi

on e

xpec

ted

durin

g ea

rly l

ife. I

f re

quire

d, i

nten

d to

run

fo

am d

isc

pigs

that

are

driv

en u

sing

wel

l pro

duct

ion.

Exxo

n/M

ica

GO

M

MC

211

Rou

nd tr

ip fr

om P

ompa

no

fixed

pla

tform

(1,2

90 fe

et)

to s

ubse

a m

anifo

ld (4

350

feet

)

8-in

ch d

ual,

2 x

28

mile

sPl

anne

dW

ax d

epos

ition

is e

xpec

ted

and

will

var

y de

pend

ing

upon

the

type

of

wel

ls p

rodu

ced.

Dur

ing

early

pro

duct

ion,

the

int

entio

n is

to

adop

t a

cons

erva

tive

pigg

ing

appr

oach

whe

re b

i-dire

ctio

nal

disc

pig

s ar

e ru

n on

a f

requ

ent

basi

s us

ing

oil

prod

uced

fro

m p

latfo

rm w

ells

. W

hen

pigg

ing

freq

uenc

y is

est

ablis

hed,

a d

ecis

ion

will

be

mad

e w

heth

er t

o us

e ga

s ins

tead

of o

il as

driv

e m

ediu

m.

Texa

co/G

emin

iG

OM

MC

292

Rou

nd tr

ip fr

om V

K-9

00fix

ed p

latfo

rm (3

40 fe

et) t

o su

bsea

man

ifold

(3,3

93

feet

).

12-in

ch d

ual,

2 x

27.5

m

iles

Prod

ucin

gN

o w

ax d

epos

ition

is

expe

cted

. I

f an

y pi

g is

run

, it

is f

or l

iqui

d di

spla

cem

ent.

Int

end

to u

se f

oam

pig

pro

pelle

d by

bu

ybac

k ga

s.Ex

istin

g ho

st c

ompr

esso

r will

be

used

.

Con

oco/

Jolie

tG

OM

GC

184

One

way

from

TLP

(176

0 fe

et) t

o ce

ntra

l pro

duct

ion

plat

form

(616

feet

)

10-in

ch (f

lexi

ble)

/14-

inch

(rig

id) d

ual

diam

eter

oil

line

& 8

-in

ch (f

lexi

ble)

/10-

inch

(rig

id) d

ual

diam

eter

gas

line

. Fl

exib

le li

nes

6 m

iles

and

rigid

line

s 6.

2 m

iles

Prod

ucin

gO

il lin

e pi

gged

twic

e pe

r m

onth

usi

ng f

oam

and

dua

l dia

met

er p

igs

to

rem

ove

wax

dep

ositi

on.

Gas

line

is p

igge

d ev

ery

two

mon

ths.

Shel

l/Tah

oe II

GO

M

VK

783

Rou

nd tr

ip fr

om B

udlit

e fix

ed p

latfo

rm (2

75 fe

et) t

o da

isy

chai

ned

wel

ls (1

500

feet

)

6-in

ch d

ual o

il lin

e,

4-in

ch d

ual g

as li

ne,

2 x

12 m

iles

Prod

ucin

gTh

e ga

s pr

oduc

ing

flow

lines

wer

e pi

gged

onc

e us

ing

foam

pig

. N

o ot

her p

iggi

ng o

pera

tions

per

form

ed.

Shel

l/Pop

eye

GO

M

GC

116

Rou

nd tr

ip fr

om S

outh

Ti

mba

lier

A f

ixed

pl

atfo

rm (3

37 fe

et) t

o su

bsea

man

ifold

(2,0

40 fe

et)

6-in

ch d

ual l

ines

, 2 x

25

mile

sPr

oduc

ing

Foam

pig

with

gau

ging

pla

te w

as r

un s

hortl

y af

ter

star

t-up

. Bot

h pi

g an

d pl

ate

wer

e da

mag

ed d

urin

g tra

nsit.

Sus

pect

pig

ging

isol

atio

n va

lve

on m

anifo

ld is

par

tially

clo

sed.

Wax

dep

ositi

on is

exp

ecte

d.

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BP/

Pom

pano

GO

M

MC

28R

ound

trip

from

VK

-989

fixed

pla

tform

(1,2

90 fe

et)

to su

bsea

man

ifold

(1,8

50

feet

)

3-in

ch T

FL s

ervi

ce

and

test

line

s, 8

-inc

hdu

al p

rodu

ctio

n lin

es,

2 x

4.5

mile

s

Prod

ucin

g8-

inch

flo

wlin

es a

re p

igge

d ev

ery

six

mon

ths

to r

emov

e w

ax d

epos

its

usin

g so

lid-c

ast

bi-d

irect

iona

l di

sc p

igs

(K-D

isc)

. Driv

e m

ediu

m u

sed

is d

ead

oil f

rom

sto

rage

tank

(900

bar

rels

) sup

plem

ente

d by

pro

duct

ion

from

pla

tform

wel

ls.

Neg

ligib

le w

ax re

turn

s hav

e be

en o

bser

ved.

BP/

Troi

kaG

OM

GC

244

Rou

nd tr

ip fr

om B

ullw

inkl

e fix

ed p

latfo

rm (1

,350

feet

) to

subs

ea m

anifo

ld (2

,670

fe

et)

10-in

ch d

ual

flow

line,

2 x

14

mile

sPr

oduc

ing

Reg

ular

wax

rem

oval

bei

ng p

erfo

rmed

usi

ng s

olid

cas

t bi

-dire

ctio

nal

from

flo

wlin

e op

erat

ing

cond

ition

s. A

dopt

ed p

rogr

essi

ve p

iggi

ng p

rog

pigg

ed.

Exxo

n/Zi

ncG

OM

MC

355

Rou

nd tr

ip fr

om A

laba

ster

fix

ed p

latfo

rm (4

68 fe

et) t

o su

bsea

man

ifold

tem

plat

e (1

,460

feet

)

8-in

ch p

rodu

ctio

n, 8

-in

ch te

st/s

ervi

ce li

ne

and

4-in

ch h

igh-

pres

sure

pro

duct

ion.

A

ll lin

es 6

mile

s.

Prod

ucin

gFl

owlin

es a

re p

igge

d on

a m

onth

ly b

asis

to

rem

ove

cond

ensa

te a

nd

sand

. B

atch

ing

pigs

are

run

to a

pply

cor

rosi

on in

hibi

tor.

No

pigs

hav

e be

en ru

n to

spec

ifica

lly re

mov

e w

ax.

Petr

obra

s/A

lbac

ora,

Mar

lim,

Bar

racu

da

Cam

pos

Bas

inR

egio

nR

ound

trip

from

floa

ting

prod

uctio

n fa

cilit

y or

fixe

d pl

atfo

rm (3

70-2

,658

feet

) to

man

ifold

or i

ndiv

idua

l wel

ls

(370

- 3,6

40 fe

et)

Flex

ible

line

s ran

ge

from

2.5

-inc

h x

4-in

ch, d

ual 4

-inc

h, 6

-in

ch x

4-i

nch,

and

8-

inch

x 1

0-in

ch.

Tieb

ack

dist

ance

s ra

nge

from

0.8

to 6

.5

mile

s

Prod

ucin

gFo

am, d

ual d

iam

eter

man

drel

and

cup

/dis

c m

andr

el p

igs

are

run

on a

re

gula

r bas

is to

rem

ove

wax

and

liqu

id.


H-0806.35 19-3 1-Dec-00

To prevent excessive build-up of solids (wax, scale, sand, etc.) by scraping the

pipe interior and removing solids from the line.

To displace accumulations of water or other fluids (corrosive) from low points

in the line.

Apply corrosion inhibitor or biocides through batching.

The most common requirement in deepwater hydrocarbon applications is tocontrol wax deposition. Because of the colder environment associated withdeepwater, the productions fluids have greater probability of falling below their cloud point resulting in wax formation and deposition. This is especially the case during system turndown when restricted flow rates imply lower fluidtemperatures. The nature of the wax deposition can be exacerbated by the inclusion of other components such as sand, scale corrosion and asphaltenes. The mixture can become easily hard and difficult to remove.

In gas lines, conditions can occur where liquids condense and collect on the bottom of the pipeline. Large liquid accumulations will limit throughput byincreasing pressure loss, increase local pipeline corrosion and increase thepotential for hydrate formation. They are also liable to be swept up by the gas, resulting in the production of hydrodynamic or terrain slugs that can exceed the capacity of the process receiving facility. Managing liquid accumulation through regular line displacement, will maintain pipeline integrity, optimize flowconditions, and enable the receiving facility (slug catcher/separator) to beeconomically designed.

Inhibitors and biocides are used to protect the pipeline from being attacked and corroded. Although chemicals can be added to the product flow to provide pipeline protection, they are not completely effective because of their inability to reach all the inside surface of the pipeline. Through running regular slugs of corrosion inhibitor or biocide between two batching pigs, the majority of the inside surface of the pipe can be coated and thus protected. It should be noted that only the top center section of the inside pipe may not be coated.

Although, pipeline and flowline inspection is not considered an integral part of flow assurance pigging requirements, it is considered worthy of brief discussion because of its potential impact on system design and operation. In the Gulf of


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Mexico, current regulations (embodied in Volume 49 of the Code of Federal Regulations, Parts 192.150-Transportation of Natural and Other Gas by Pipeline, and 195.120 Transportation of Hazardous Liquids by Pipeline) do not require the periodic internal inspection of subsea production flowlines unless the lines are 10-inch nominal or greater and transporting liquids or gas back to onshorefacilities. However, it is possible that regulations may change in the future that require intelligent pigs to be run. Therefore, consideration should be given to design (i.e. constant ID, 5D bends, etc.) and operation (i.e., aggressive pigcleaning, etc.) of the pipeline system to facilitate the smooth passage of intelligent pigs.

19.4 System Configurations & Operating Modes

There are several offshore pigging configurations available. They can beclassified into three basic categories:

Surface One Way Pigging

This configuration is the simplest and is similar to that of land based systems.Refer to Figure 19-1. The launcher and receiver are located at the surface, and all pigging operations are conducted in the direction of normal flow using the on-stream fluid and flowrate to propel the pig through the continuous line. The lines that are usually pigged are either oil or gas export pipelines.

The general configuration is the connection of a shallow water fixed platform to a deepwater host that could be a fixed platform, tension leg platform (TLP), deep draft caisson vessel (DDCV) or semi-submersible vessel. The most common arrangement worldwide is fixed platform-to-fixed platform. Pigging is easily accomplished since the pigging path between fixed platforms tends to be rigid with uniform inside diameter. In deeper waters the pigging path can become more complex since rigid pipe is combined with flexible pipe and risers. This has been the case for some developments that have employed TLPs and semi-submersible as deepwater hosts. An example of TLP-to-fixed platform isConocos Joliet development in the Gulf of Mexico. Because the flexible and rigid steel pipe sections were of different diameter this has limited the type of pigs run.

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Subsea Loop Pigging

This configuration involves a launcher and receiver located at some host, and two piping runs that are connected together to form a continuous loop. The piping runs tieback a remote subsea facility (i.e. single well, manifold etc) to a deepwater or shallow water host. Refer to Figure 19.2. Each leg can be dedicated as a returnline for production or may serve as a different function (i.e. test line). As a minimum, the host must have a pressure source that is capable of driving the pig around the loop and into the inward bound flowline. The fluid used to launch and drive the pig must be compatible with the produced fluid.

Operating modes for loop or round trip (RT) pigging depend upon theconfiguration of the remote subsea facility. Assuming the remote subsea facility comprises a dual manifold header with single pigging isolation valve, the possible operating modes are as follows:

Round Trip Using Pump/CompressorWell production is shut in and the pigging isolation valve is opened. With the host pump or compressor, launch pig down the outward-bound flowline and drive pig back to the host via the other flowline. Close the pigging isolation valve and resume production.

This operating mode is the simplest and most common arrangement for round trip pigging. However, it represents the greatest downtime in production. It is suited to systems that have production fluids that are considered too hot for the pig, or production flowrates that are too high or low to effectively pig with. It also mitigates the risk of losing the flowline to a wax plug since the progress of the pig is directly controlled with either the pump or compressor for the duration of the trip.

Round Trip Using Well ProductionShut- in well production and open the pigging isolation valve at the manifold.Using a pump or compressor, propel the pig down the outward-bound flowline around the subsea pigging loop into the return flowline. Close the pigging isolation valve and restart well production to drive the pig back to the host.

This operating mode enables downtime to be reduced since production can be restarted once the pig traverses the loop. Since the return of the pig is dependent upon well production, the well must have sufficient pressure to

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INTEC ENGINEERING, INC. DEEPSTARMULTIPHASAE DESIGN GUIDELINE

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overcome the static and fluid friction losses. This may not be the case in late field life, when reservoir pressure has declined. Also, there is no direct method for controlling the progress of the return pig except for manipulating the surface choke and possibly the subsea choke.

Round Trip and Drive Against Well ProductionOpen the pigging isolation valve at the manifold and drive the pig against well production using a compressor or pump. When the pig traverses the loop and into the other flowline, close the pigging isolation valve. The pig will then be driven back to the host with well production.

This operating mode involves less production downtime since the well is not shut in during pig delivery. However, this comes at the expense of requiringgreater pump/compressor capacity to drive against manifold pressure.Although production is maintained during pig delivery, it is at a reduced rate.

Comparing the above operating modes, it is apparent that production downtime can be reduced by employing a three- line arrangement with piggable wye. Refer to Figure 19-3. With this arrangement, well production can be maintained in one leg while the other legs remain dedicated to pig transit. Because residual fluids and solids are displaced from the lines during pigging, the process capacity of the host must be sufficient to handle the simultaneous arrival of production and displaced fluids. If this is not the case, then either production rates or pigging operation will have to be compromised.

A good example of a looped configuration that employs three lines, and with different line sizes, is Exxons Zinc development in the Gulf of Mexico. Three steel flowlines approximately 6 miles long connect the Zinc manifold template to the Alabaster fixed platform. The lines are a single 8- inch low-pressure bulk production, single 8- inch test/service line and 4-inch high-pressure line for testing individual wells. Refer to Figure 19-4. Bi-directional cup pigs have beenlaunched regularly to remove sand and condensate from the 8- inch lines. In pigging the 4-inch line, foam and sphere pigs have been launched and driven into the 8-inch line via the pigging valve assembly on the manifold. The 4-inch pigs were recovered when the 8- inch lines were pigged.

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Subsea One-Way Pigging

This configuration applies to those developments that do not provide convenient or viable surface entry and/or exit point for pigging. The development may be the single flowline tieback of a subsea facility to shallow water host or system that has an incompatible pigging path (i.e. riser and pipeline are of different diameter, there is a restrictive bend, material limitations, etc.) The latter case is typical of

branch/trunkline tie- ins. In these cases, a subsea pig launcher (SPL) or subsea pig receiver (SPR) is necessary.

The SPL and SPR provide the ability to get pigs into or out of lines that do not have a surface access point. Refer to Figure 19-5. They provide the same functions as of the conventional land-based launcher and receiver except they are engineered specifically for subsea deployment and rely upon surface vesselsupport. Pigs can be launched subsea using a SPL and propelled towards the host receiver or SPR. The pressure source for launching and propelling the pigs can be either well production and/or fluid supplied from surface vessel. The SPR plays the opposite role to the SPL and is responsible for catching the pigs launched from the host launcher or SPL. The SPR requires a connection that conveys displaced flowline contents to a surface vessel or into another flowline.

A good example of an operational SPL is the one used by BP Amoco in their Eastern Trough Area Project (ETAP) development in the North Sea. The SPL is located on a subsea production manifold that is tied back 22 miles to the Central Processing Facility (CPF) by a 16-inch flowline. Since deployment, the SPL has successfully launched several bi-directional mandrel pigs that have removed wax from one of the longest subsea tiebacks in the North Sea.

19.5 Pig Types & Selection

There are four main types of pigs that can be used for flow assurance purposes: sphere, foam, solid-cast and mandrel.

19.5.1 Mandrel

These pigs are assembled from a number of component parts (plastic and metal), which are mounted on a shaft so that they can be replaced or reconfigured as required. The conventional mandrel pig will comprise sealing elements that are

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1-D

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9-5

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-6:

Typi

cal M

andr

el P

igs

Con

ical

Sea

ling

Cup

s w

ith B

lade

sPi

ston

Typ

e Se

alin

g C

ups

Con

ical

Sea

ling

Cup

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-7:

Man

drel

Pig

Sea

ling

Elem

ents

INTEC ENGINEERING, INC. DEEPS TARMULTIPHASE DESIGN GUIDELINE

H-0806.35 19-16 1-Dec-00

used to drive the pig and also cleaning elements, if the intended application is to clean the line. Refer to Figure 19-6.

The sealing elements are normally made from polyurethane and can be divided into piston-type cup, conical cup and flat disc. Refer to Figure 19-7. The piston-type cups have a pressure-energized shape that provides a good seal and some compensation for wear. They are normally mounted on large diameter flanges, which increase the risk of metal-to-metal contact in the line. Because of the mall amount of contact material, this limits their ability to conform to ovality.Therefore, they are susceptible to losing their seal when traveling through lines that have significant out-of-roundness.

Conical cups are more accommodating in sealing within pipes of irregularcircularity or roundness. Also, the geometry of the cup enables a greater radial load and hence tighter seal to be produced when differential pressure is applied.This results in swabbing operations being more efficient. Although a higher wear rate might be expected because of the tighter seal, this is compensated for by the exceptionally wide wear surface that the conical cup provides. Also, because of the tighter seal, conical cups have been known to smear soft deposits against the inside wall. This process makes the cleaning operation ineffective.

Solid discs have been used where bi-directional pigging has been required.Usually four discs sized to be an interference fit are mounted on the pig body.Since they have little or no capability to compensate for wear, they need frequent replacement.

The cleaning elements are components designed to remove solid or semi-soliddeposits and can either be wire brushes, blades, discs or a combination. The wire brushes are generally mounted on springs to force them into contact with the pipe wall and compensate for wear. For smaller diameter pigs, the wire brushelement(s) are usually a continuous wire wheel. Wire brushes tend to be suitable for removing only hard deposits. Based upon BP Amocos experience in pigging various main oil lines (Beatrice, Ninian, Wytch Farm) they recommend that wire brushes be avoided in soft waxy lines since they quickly become clogged up.

Blades are suitable for removing both hard and soft deposits. The blades can be made from steel for extreme situations, but normally they are molded frompolyurethane that is of slightly harder grade than the sealing elements. Various

INTEC ENGINEERING, INC. DEEPS TARMULTIPHASE DESIGN GUIDELINE

H-0806.35 19-17 1-Dec-00

shapes are available with the most common being the 3-Rib blade. Apart from its basic simplicity that keeps tooling costs low, it has the added advantage of imparting a slow rotation to the pig that contributes to reducing effective wear rates.

Cleaning discs are similar to the sealing discs except that they are sized below the nominal pipe ID and are made harder. Independent studies performed by Shelland Petrobras, verified that discs were the most effective cleaning element in removing solids of various hardness. Bi-directional disc pigs have beensuccessfully used in a number of recent deepwater cleaning applications (i.e. BP-Amoco Troika, BP-Amoco Pompano, etc.). There is also intention to use the same pigs on other upcoming field developments (i.e. Shell Macaroni, Exxon Mica, etc.). Lastly, disc pigs have also performed well in removing condensate when combined with solid drive discs.

19.5.2 Solid Cast

Solid cast pigs are similar to mandrel pigs except they are molded in one piece, generally from polyurethane, whereby the body, sealing and scraping elements are an integral unit. Refer to Figure 19-8. They are as effective as the mandrel type pigs in removing liquids and soft to medium deposits. Solid cast pigs arenormally only available in the smaller sizes (12 inch and below). Theirdevelopment was a result of labor costs for assembling and replacing parts on small pigs being significantly higher than the cost of a new pig.

The lighter and more flexible design mitigates the risk of damaging the flowline and helps to negotiate tight bends and other irregularities. However, field repairs are not possible and complete replacement is usually necessary in the event of one part becoming damaged.

19.5.3 Foam

Foam pigs are widely used in the pipeline industry. Petrobras has extensively used them to remove soft to medium wax deposits. They are particularly suitable when developing a pigging program for a line that has not been regularly pigged and which may contain unexpected restrictions. Foam pigs are manufactured in many designs and sizes. They are manufactured from polyurethane foam ofvarious densities ranging from low (2-4 lb/ft3), medium (5-7 lb/ft3), and high (8-10 lb/ft3). Each of the density ranges offers a different flexibility and wear resistance, the lower density being more flexible and subject to wear than the

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Solid

Cas

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H-0806.35 19-19 1-Dec-00

higher density. Although normally found in bullet shape form, they can have concave, flat, or bullet noses on each end. An elastomeric coating is normally


H-0806.35 19-20 1-Dec-00

applied to the base to provide for maximum seal against the propelling force.Some even have coating on the surface to enhance the sealing and wipingcapability of the pig, and to increase its wear resistance. Normally, the overall length of the pig is 1.75-2 times the pipe diameter, with the base to shoulder (the point where the surface bearing area begins to taper towards the nose) dimension measuring 1.5 times the diameter. Foam pigs are currently manufactured indiameters from 0.25- inch to 108-inch, with increments of 0.125- inch available in diameters under 12-inch.

There are numerous designs of foam pigs available, but the most frequently used are swabs, bare squeegees, crisscross, silicon carbide and wire-brush. Refer to Figure 19-9. The swabs are a low-density design with base coated for a seal and are used for the removal of soft materials, drying and absorption of liquids (a swab can absorb up to 75 percent of its volume in liquids). The bare squeegees range from medium to high-density foam with coated base and are used for liquid removal and light cleaning. Crisscross foam pigs are made from either medium or high-density foam with coating on the surface bearing area. They are used for dewatering, batching, cleaning and removal of solids (soft to medium hardness).Silicon carbide is similar in make-up to the crisscross, except the bearing area is covered with silicon carbide/aluminum oxide grit or straps. Mostly employed for scraping or cracking hard deposits such as oxides or carbonates (normally for short runs). Finally, the wire brush is made from medium to high-density foamwhere bristle straps (steel, brass or plastic) cover the total bearing area or are incorporated into a crisscross pattern. This wire brush pig is used for maximum scraping of hard deposits such as mill scale.

19.5.4 Sphere

Spheres have been mostly used for sweeping liquids from lines and have some limited success in solids removal. Conventional spheres are simply hollow balls, fitted with flush or recessed valves to enable them to be filled and inflated with glycol-water mixture to achieve the desired diameter. For small pipe diameters, spheres are normally made solid. They are generally molded from polyurethane in either one piece (requires rotational mold technique) or from two halves, which are subsequently bonded together. The latter method is usually the leastexpensive and is understood to have been developed to the point wherehomogeneity can be guaranteed.

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Typi

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oam

Pig

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H-0806.35 19-22 1-Dec-00

Because differential pressure requirements for propelling spheres are relatively low, this results in minimum wear other than cuts and abrasions from the internal surfaces such as weld penetrations. If spheres do not have constant wall thickness then inflation will expand the thin wall section more than the other surfaces and distort the sphere. This will cause irregular wear and premature failure

19.5.5 Pros and Cons

The pros and cons of the mandrel, solid-cast, foam and sphere pigs aresummarized in Table 19.2.

19.5.6 Special Pig Types

Whilst the majority of flow assurance pigging requirements can be satisfied with standard pigs, there are occasions where special type pigs must be applied. The following discusses the most relevant of the specialized pigs available:

Multi Diameter Pig

This type of pig has been used by several operators where the pigging path has comprised of several different diameters. Pig construction usually comprises a disc for the smaller diameter and overlapping slotted discs (flaps or petal discs) for the larger diameter. The slotted discs will fold in the small pipeline and resume their original shape (to effect a seal) when they enter the larger pipeline. Petrobras for fields in the Campos Basin region have attempted to use dualdiameter disc pigs instead of foam pigs to remove hard wax deposits. Initial runs through 2.5 inch and 4- inch pigging path, proved that the dual diameter could traverse successfully but did not remove wax effectively. Based upon field experience the dual diameter pig was re-developed to be more effective inremoving harder deposits.

By-Pass Pig

This pig is fitted with what is effectively a relief valve that is set to open at a pre-chosen differential pressure. If during a cleaning operation, the pig builds up a large accumulation or slug of debris ahead of it, the pressure differential across the pig will rise as the pig works harder. If a standard cleaning pig was used, the accumulation may increase until the pig became stuck or substantially damaged.This situation is mitigated with a pressure by-pass pig, since once the pre-setdifferential pressure is reached, the by-pass valve opens, thereby allowing a


H-0806.35 19-23 1-Dec-00

substantial volume of fluid or gas to flow through the pig body. This results in the debris being jetted or blown away from the front of the pig, after which time the differential required to run the pig will drop, the by-pass valve will close, and the pig will move on.

A more sophisticated version of this pig type has been developed for the purpose of controlling the velocity and hence the performance of the pig. The variable speed pig was originally developed by Apache Industries of Edmonton, Canada, and was designed to run independent of the normal product flow and speed within a pipeline where high velocities were present (i.e. gas transmission and exportlines). By regulating the amount of by-pass through the body, the speed of the pig can be controlled within a pre-set range. The variable speed pig senses its velocity, compares this to a pre-set value, then controls the volume of by-pass to maintain the required speed. Although, this pig would be ideal for removing solids and liquids (i.e. limit slug rate) when gas driven, it would be difficult to justify because of its relative high cost.

Shunting Pig

This three-section pig has been specifically developed to recover stuck or lost pigs from pipelines. It is generally accepted that running a second pig of similar or identical design to the one that is stuck or lost is futile, since there is a high probability that it will succumb to the same misfortune as the original. The second pig normally becomes damaged as a result of too much load being applied to push a stuck or lost pig. Using a three section shunting pig, it has beenrecognized that the leading section will probably be damaged as it pushes thedebris ahead of it, but drive can be maintained because of the second and third sections not coming into contact with the debris being pushed. Additionally, to further assist the recovery of a stuck or lost pig, the shunting pig can bedeliberately made heavy to increase momentum.

Gel Pig

Gel pigs have been successfully used in a number of applications involving solids removal, liquid displacement, recovery of stuck pigs, product separation, and application of in-situ coatings (i.e. inhibitor, biocides, solvents etc.). They are based upon combining a base fluid (water, diesel, crude, solvent etc.) with a

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Tabl

e19

-2:

Pros

and

Con

s of P

igs T

ypes

Pig

Typ

ePr

osC

ons

Man

drel

R

eadi

ly

reco

nfig

ured

w

ith

diff

eren

t se

alin

g an

d sc

rapi

ngel

emen

ts to

suit

the

appl

icat

ion.

For

size

s la

rger

tha

n 12

-inch

, sig

nific

ant

cost

sav

ings

can

be

mad

e in

rep

laci

ng w

orn

com

pone

nts i

nste

ad o

f ent

ire

pig.

T

he m

ost

aggr

essi

ve i

n re

mov

ing

soft

to

hard

dep

osits

. D

isc

conf

igur

atio

ns h

ave

succ

essf

ully

rem

oved

san

d an

d a

wid

e ra

nge

of w

ax ty

pes.

E

ffic

ient

in

liqui

d re

mov

al e

spec

ially

whe

n cu

p se

als

are

empl

oyed

.

Dep

endi

ng o

n se

alin

g el

emen

t, dr

ive

fluid

, lin

e co

nten

ts,

etc.

th

e m

andr

el p

ig i

s go

od f

or t

rip

dist

ance

s of

bet

wee

n 10

0 to

50

0 m

iles.

C

onst

ruct

ion

mak

es t

hem

hea

vier

tha

n eq

uiva

lent

siz

ed p

igs.

Thi

s te

nds

to i

ncre

ase

risk

to

dam

agin

g pi

pelin

e es

peci

ally

whe

n ga

sdr

iven

. A

lso,

the

hea

vier

man

drel

req

uire

s gr

eate

r di

ffer

entia

l dri

ve

pres

sure

.

Man

drel

pig

s ha

ve s

ealin

g an

d sc

rapi

ng e

lem

ents

gen

eral

ly s

ized

clo

se

to th

e lin

e bo

re.

To

avoi

d th

e pi

g fr

om b

ecom

ing

stuc

k or

dam

aged

, a

cons

tant

bor

e an

d m

inim

um b

end

radi

us o

f 3-5

D is

req

uire

d.

Man

drel

s co

nfig

ured

with

fla

t di

scs

are

not

good

at

nego

tiatin

g di

ffic

ult g

eom

etri

cal f

eatu

res.

Solid

-C

ast

Si

mila

r ef

fect

iven

ess

as t

he m

andr

el t

ype

pigs

for

liq

uid

and

soft

to m

ediu

m d

epos

its r

emov

al.

G

ener

ally

lig

hter

tha

n m

andr

el a

nd c

onta

ins

no m

etal

par

ts.

The

re

is

less

ri

sk

in

dam

agin

g th

e flo

wlin

e or

pr

oces

seq

uipm

ent.

Fi

eld

repa

irs

are

not

poss

ible

and

com

plet

e re

plac

emen

t is

usu

ally

ne

cess

ary.

M

ost

solid

-cas

t pi

gs h

ave

a ho

llow

bod

y th

at is

sus

cept

ible

to

dam

age

if pi

g is

sub

ject

ed t

o hi

gh d

iffer

entia

l pr

essu

re w

hen

stuc

k.

The

ho

llow

bod

y ca

n ex

pand

and

blo

w o

ut th

e no

se o

f the

pig

.

Alth

ough

mor

e fle

xibl

e th

an e

quiv

alen

t m

andr

el p

ig,

the

solid

-cas

tre

lies u

pon

cons

tant

bor

e an

d m

inim

um b

end

radi

us o

f 3-5

D.

Sphe

re

Sphe

res

are

easy

to

hand

le a

nd c

an b

e re

-gau

ged

(dia

met

er

rese

t) b

y in

flatio

n to

allo

w fo

r w

ear.

Si

nce

they

rol

l fre

ely,

the

y ca

n be

aut

omat

ical

ly l

aunc

hed

at

pred

eter

min

ed

inte

rval

s.

The

y ca

n be

pr

opel

led

alon

gho

rizo

ntal

sec

tions

of o

vers

ized

line

s an

d pa

ss th

roug

h sl

ight

ly

unde

rsiz

ed l

ines

. P

iggi

ng s

yste

ms

with

a w

ide

rang

e of

lin

e si

zes

can

be p

erfo

rmed

usi

ng l

arge

sph

eres

to

pus

h sm

all

sphe

res f

rom

gat

heri

ng li

nes i

nto

trun

k lin

es.

M

inim

um p

ress

ure

diff

eren

tial i

s re

quir

ed t

o pr

opel

sph

eres

.

In

effe

ctiv

e in

sol

ids

rem

oval

. T

end

to s

mea

r (s

oft)

or

sque

eze

past

(h

ard)

dep

osits

.

Can

dro

p in

to b

ranc

hes

off

mai

n lin

es u

nles

s th

ey a

re f

itted

with

ba

rred

tees

or

over

size

d te

es w

ith a

dow

nwar

d sl

ope.

N

ot e

ffic

ient

in li

quid

s rem

oval

bec

ause

of b

y-pa

ss.

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Thi

s m

inim

izes

wea

r an

d en

able

s pi

ggin

g to

be

perf

orm

ed a

t no

rmal

pro

duct

ion

flow

rate

s.

Can

neg

otia

te sh

ort r

adiu

s ben

ds a

nd ir

regu

lar

turn

s.

Foam

Im

prov

es s

afet

y by

red

ucin

g th

e po

ssib

ility

of d

amag

ing

line.

Fo

am p

igs

are

com

pres

sibl

e, l

ight

wei

ght,

and

flexi

ble.

T

hey

can

trav

el th

roug

h m

ultip

le-d

iam

eter

line

s, sh

ort r

adiu

s ben

ds,

redu

cing

val

ves,

dent

ed p

ipe,

and

oth

er r

estr

ictio

ns.

Mos

t m

ediu

m d

ensi

ty p

igs

can

trav

el t

hrou

gh o

peni

ngs

with

as

little

as

65%

ope

ning

.

Sim

ple

man

ufac

turi

ng m

etho

d en

able

s cu

stom

des

igns

to

be

read

ily m

ade.

If

foa

m p

igs

beco

me

stuc

k th

ey c

an b

e di

sint

egra

ted

with

pr

essu

re a

nd/o

r di

ssol

ved

with

che

mic

als.

E

asie

r to

fit i

nto

a pi

pelin

e w

ithou

t pig

trap

s

C

onsi

dere

d a

one-

time

use

prod

uct.

T

end

to b

e m

ore

expe

nsiv

e th

an t

he r

epla

cem

ent

part

s of

a m

andr

el

pig.

Pi

gs

that

co

ntai

n ir

on

sulfi

de

in

the

foam

m

ust

be

clea

ned

imm

edia

tely

aft

er r

ecei

ving

to a

void

spon

tane

ous c

ombu

stio

n.

Diff

icul

t to

clea

n an

d he

nce

stor

e sa

fely

if u

sed

to p

ig h

ydro

carb

ons.

In

here

nt

flexi

bilit

y m

akes

m

ediu

m

to

hard

de

posi

t re

mov

alin

effe

ctiv

e.

Als

o, f

oam

pig

s te

nd t

o tr

avel

dow

n lin

es t

hat

wer

e no

t in

tend

ed fo

r th

em.

Thi

s ha

s pr

oduc

ed p

roce

ss s

hut d

owns

.


H-0806.35 19-26 1-Dec-00

crosslinked gum-based polymer to form a thick visco-elastic substance. They can be made to any density and range from pre-formed pigs that are usually shipped to site within their metal mould, to a light foam that is sprayed into the line. For optimum performance, gel pigs are used in conjunction with conventional pigs.

Gel pigging is invariably expensive as the gel is usually required in largequantities and therefore must be manufactured in-situ. It is also usuallybiodegradable and this makes product life very limited.

19.5.7 Pig Selection

The success of a pigging operation depends very much on the correct pigselection. The decision should focus on the following:

Select a pig suitable for the application Select a pig which travels through the line with minimum risk Select a pig that provides optimum performance and therefore minimizes the

number of runs and production downtime.

There are many factors that influence final pig selection. The main ones to consider are:

Line contents - liquid or solids, volumes, solid consistency (i.e. soft, medium or hard), thickness, location, chemical compatibility, etc.

System design - pigging path profile (i.e. line diameters, length, elevation, size and position of valves, tees, bends, wyes, etc.), capacity of receiving facilities, propulsion media (gas or liquid), available drive pressure, etc.

As a rough guide to pig selection for solids removal, a simple decision tree has been developed. Refer to Figure 19-10. From the decision tree, it is evident that pig types fall into the general categories of disc (mandrel or solid-cast) or foam discs. For liquid removal and batching, the most suitable pig types are either cup disc (mandrel or solid-cast), foam pigs or spheres. Cup disc pigs would providethe greatest efficiency if the pigging path was deemed compatible, otherwise soft to medium density foam pigs would be used instead. Spheres as discussed previously, would be applicable if some form of pigging automation was required (i.e. high pigging frequency).

19.6 Basic System Components and Design Considerations

The section deals with basic system components and design considerations.


H-0806.35 19-27 1-Dec-00

19.6.1 Flowline System

To avoid compromising pig selection and operation, the flowline system must meet the following basic design specification:

Line Pipe To ensure smooth passage of pig during transit, a constant bore is recommended. Maximum deviation of internal diameter from the nominal should be kept to below the figures given in Table 19.3. Any internaldiameter change should be made within a transition piece of 1:5 slope.


H-0806.35 19-28 1-Dec-00

SOLIDS REMOVAL-INPUT PARAMETERS


H-0806.35 19-29 1-Dec-00

Table 19-3: Inside Diameter Maximum DeviationNominal Diameter (inches) Maximum Deviation (mm)

4 46 6

8-12 1014-20 1420-36 16

36 and above 20

Valves All valves should be full bore, have concentric inlet and outlet bores, no internal producing features and be specified by internal diameter. Valves should guarantee 100% opening and have limited or zero by-pass.

Tees/Offtakes Branch connections with outlets above 50% of nominal line size should be barred. At least three diameters of straight pipe should be installed between any two tees. To prevent solids from being pushed into manifold branches, the branches should be positioned above the pipecenterline. Also, branch isolation valves should be located as close to the manifold header as practically possible to minimize the amount of solids that could compact into the branch/valve gap

Bends The minimum radius for bends is detailed in Table 19.4 below.Besides the minimum radius, the ovality (out-of-roundness) of any bend should be limited to 3%. For 30 and 45 bends, there should be a minimum straight length of 6 feet for pipe diameters to 24- inch, and 3D for diameters of 24-inch and above.

Table 19-4: Minimum Bend RadiusNominal Diameter (inches) Minimum Bend Radius

4 and below 10D6 - 12 5D

14 and above 3D

Wyes The angle between the branches of a wye should be set at 30. The bore in the section where the branches merge should be enlarged to 105-110%of the pipeline diameter. This enables pigs to contact surfaces and expand out to their unrestrained diameter, hence reducing the friction experienced as it passes through the wye. The web between the incoming branches should be made as long as possible to maintain the separation between the bores.

19.6.2 Surface Launcher/Receiver

Surface pig launchers and receivers can be divided into three basic categories: horizontal, inclined/declined, and vertical installations. Refer to Figures 19-11 for basic layout.

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Pig

Lau

nche

r an

d R

ecei

ver

Basic

Lay

out


H-0806.35 19-31 1-Dec-00

Horizontal configurations tend to be preferred over vertical designs even although they consume more deck space. The horizontal designs tend to accommodate more standard pig types and facilitate easier handling and cleaning operations.Vertical configurations require certain pig types to be modified to achievepositive location. For example, when loading a disc pig into a vertical launcher, the nose of the disc pig must be tapered to ensure that the disc pig aligns itself vertically and effect a seal within the launch tube. There have been numerous cases where standard pigs have failed to launch because they adopted an askew position - launch fluid bypassed the seals and therefore did not create sufficient differential pressure to drive the pig. Also, vertical receivers usually require the use of internal perforated baskets to capture the returned pigs. Failure to capture the pig could result in the pig falling back into the line and possiblycompromising the closure of the isolation valve.

Inclined/declined traps tend to be used specifically for launching and receivingspheres. For launching purposes, the trap is inclined approximately 5 degrees, with the closure made higher than the neck. This permits gravity to assist the sphere to freely roll into the launch position. A sphere pin (specially designed launch valve) or pneumatically operated flap is used to release the spheresindividually into the neck of the trap for launching. Inclined/declined traps tend to be suited to the remote operation of multiple spheres.

Both the surface launcher and receiver should be configured to be multi-functional. This will allow for the handling of different types of pigs andaccommodate the possibility that any pigs may have to be sent or recovered in the direction of normal flow.

The typical barrel length on a launcher trap should be 1 times the length of the pig from the bypass line to the reducer weld and on receiver traps 1 times the length of the pig from the bypass line to the closure weld. If a cleaning pig is to be run with foam pig in tow (accommodates locating device) or an intelligent pig is to be run, then the length of the barrel needs to be increased accordingly.

The use of an eccentric (taper at top) rather than concentric reducer at the end of the barrel is the preferred arrangement. The eccentric reducer better assists in locating the first drive seal in the launch tube and provides the pig a smooth transition from line pipe to oversized barrel when receiving.


H-0806.35 19-32 1-Dec-00

The pressure rating of the launcher and receiver should match the pressure rating of the incoming pip ing and valves and therefore should meet the design code of ASME B31.4 for liquid pipelines or ASME B31.8 for gas pipelines or other applicable code.

The kicker line on the launcher and the bypass line on the receiver should be sized generously. This ensures that pigs can be launched even when they are not effecting a good seal within the reducer. Also, a generously sized bypassconnection will ensure the smooth arrival of pigs into the receiver under various flow conditions.

To prevent inadvertent movement of pig within launcher (forward movement into isolating valve or backward movement resulting in seal loss) and dangerous pressure traps between pig and valve, a pressure balance line should be runbetween the two extreme ends of all pig traps.

To verify the launch and receipt of a pig, all traps require to be fitted with some type of pig passage indicator. The indicator can either be a mechanical or electrical (magnetic field) type providing that it satisfies the criteria of being bi-directional, flush with the internal pipe wall and can be safely replaced under pressure using standard methods

To avoid the potential problems as a result of too much wax arriving at the receiver (i.e. failure to open/close isolation valves, etc.), arrangements should be made to heat trace or provide a means to inject solvent into the receiver or surrounding pipework. The internals should be designed so that they are as free draining as possible to minimize wax deposition. The injection point should also provide the means to introduce chemicals or gels during batching operations.

To ensure safety, the launcher and receiver should have vent and drain ports, reliable pressure gages and seals, and appropriate interlocks to prevent the pig trap from being opened while pressure remains inside.

19.6.3 Subsea Launcher/Receiver

Subsea pig launchers and receivers (SPL/SPR) have similar functions toconventional surface launchers and receivers except they are engineeredspecifically for subsea deployment and therefore rely upon surface vessel support. They are normally installed onto a flowline hub profile that incorporates an


H-0806.35 19-33 1-Dec-00

isolation valve along with guidance/support structure to accommodate the SPL or SPR.

The SPL/SPR can either be an active (remotely operated) or passive (ROVoperated) design. The decision between active and passive will have a significant impact on design and operation of the SPL/SPR and production system. Ifconfigured to be active, valves on the SPL/SPR and flowline (hub isolation) require to be hydraulically actuated by the subsea controls system. This represents higher system cost and operational risk. This explains why the majority ofSPL/SPR designs adopt a passive approach.

To launch a pig, a communication path for the kicker fluid is required from either the subsea production system (i.e. well production, methanol injection, etc.) or surface support vessel. If the source of kicker fluid is from the subsea production system then another single hub connection with isolation valve, in parallel with the main hub connection (pigging path) is required. Alternatively, an integral multi-hub connection could be used that employs parallel or concentric bores. If kicker fluid is supplied from a surface support vessel, then the number of subsea interfaces and valves can be minimized. However, a service umbilical is required to connect the surface pressure source to the SPL kicker line. In the event the surface vessel requires to suddenly drive off location (i.e. loss of dynamicpositioning), then the service umbilical should be capable of emergencydisconnect. The emergency quick connect/disconnect system will terminate and isolate the service umbilical at the surface or subsea

For receiving a pig, similar connections to the above would be required for the bypass path.

Specific features of a deepwater SPL/SPR are addressed below:

The SPL/SPR should accommodate several utility pigs that can be

individually launched or captured. To cover the possibility of intelligent

pigging, the barrel section should be capable of being replaced or extended.

A positive pig release and retaining mechanism is required that can be reliably

operated by ROV. The preferred system should prevent the possibility of pig

hang up and slipping.


H-0806.35 19-34 1-Dec-00

Employ an ROV operated flowline connector that is capable of multiple make

and break. Guidance will be integral to the connector via a large swallow area

that captures the hub and aligns the seal bore prior to make-up. The connector

will also provide the means to pressure test after make-up.

Rough alignment systems are required for initial location on the flowline hub profile. Depending on depth, this could be a minimum of two API guideposts that have guidewires connected back to the surface or guide funnels that are incorporated on SPL/SPR or flowline hub.

A simple soft landing system is required that minimizes the likelihood of

damaging sealing mechanisms during installation.

To eliminate the requirement of handling the SPL/SPR under pressure or full

of launch fluids, a method of relieving pressure and purging prior to SPL/SPR

retrieval should be provided.

For SPL/SPR that employ dual connections that permit the flow of kicker or

bypass fluid, a fine alignment system will be required to orient the seal

mechanisms of each connector prior to engagement.

A pressure cap should be provided that blanks off the flowline hubs when the

SPL/SPR is not installed. This will be in line with dual barrier philosophy.

Identical arrangements as used by the SPL/SPR for installation and alignment

on the flowline hub(s) will be used by the pressure cap. To ensure safe

operation, the pressure cap should have a ROV operated vent arrangement that

enables pressure to be bled down prior to its removal.

A test and transportation stump should be provided to serve both the pressure

cap and SPL/SPR. The test and transportation skid must allow function and

pressure testing and facilitate the transferring from the horizontal to vertical

and vice versa.

The SPL/SPR and pressure-retaining cap, requires structural framing that is

designed in accordance with good practice for offshore handling,

transportation and installation. The structural frame should act as a mount for

the SPL/SPR barrel and support the installation mechanisms including the

guidecones, guide sleeves and connectors.


H-0806.35 19-35 1-Dec-00

The SPL/SPR should be configured for simple installation and retrieval. If

deployed from dynamically positioned diver support vessel, then crane hook

should be sufficient, providing the hook enables ROV to easily make and

break the connection.

19.6.4 Propulsion

Liquid or Gas

Most configurations require some pressure source to launch and propel pigs through the pipeline system. Since the effectiveness of a pigging operation is dependent upon controlling the speed of the pig, selection of the correct method of propulsion is critical.

The arrangements for pigging multi-phase production flowlines are different than those for gas and oil export lines. In oil export or water injection lines, propulsion and speed control is relatively straightforward since it involves controlling the output of the final separator stage or the booster pumps. For gas export lines, although speed control can be more involved because of potential liquid hold-upand steep riser sections, the speed of the pig again is essentially determined by the on-stream flow conditions set by the separator or compressor.

When an operator requires pigging of multi-phase production flowlines, adecision must be made whether to use liquid or gas propulsion. The decision will depend upon many factors (i.e. flowline conditions, configuration, operatingstrategy, fluid availability, process capacity, etc.).


H-0806.35 19-36 1-Dec-00

Figure 19-11: Liquid Volume Requirements for Round Trip Pigging

If the flowline is expected to contain deposited solids of unknown volume and composition, then liquid propulsion is strongly recommended. Liquid propulsion would provide the ability to directly control pig progress, enhance pig-cleaningperformance, and produce the necessary feedback for establishing a database usedin optimizing pigging frequency. Also, another major benefit of liquidpropulsions is the ability to determine the approximate location of the pig if it should become inadvertently stuck (i.e. assuming the seals had not failed). The major drawback of liquid propulsion, especially if dealing with a gas production system where liquid production is not available for pigging, is the logisticsassociated with the storage, handling and disposal of the liquid. Figure 19-12,depicts the liquid volume requirements for round trip systems of differentflowline sizes and tieback lengths. If the liquid recovered during the pigging operation can be reused as pig propellant, then the initial liquid volumes can be reduced accordingly.

0

10000

20000

30000

40000

50000

60000

0 5 10 15 20 25 30 35 40 45

Tie-Back Distance (miles)

Liqu

id P

ropu

lsio

n Vo

lum

e (b

arre

ls)

6 Inch ID

8 Inch ID10 Inch ID12 Inch ID


H-0806.35 19-37 1-Dec-00

If conditions within multi-phase flowlines are considered relatively benign, then providing the necessary preparations and precautions are taken, then gaspropulsion should be suffice. Because of the gas compressibility, speed control is more difficult but can be achieved to some degree using a number of methods.These are discussed in Section 19.7.2.

Types of Fluid

Liquid propellants could be water, lease crude, produced crude or diesel. Water is inexpensive and is readily available offshore. However, uninhibited water would represent a high risk of forming hydrates or in the case of waxy lines, the water could harden the wax deposits making subsequent removal more difficult. The use of hot water is not considered viable because of the cooling effect associated with deepwater ambient temperatures. Lease and produced crudes are relatively inexpensive and their availability will depend upon the host infrastructure. Diesel is an excellent propelling fluid, especially if pigging operation involves waxremoval. Since diesel is a solvent, it will tend to soften the removed wax and layers of wax on the pipe wall. However, this effect diminishes with lower ambient temperatures. For significant volumes, diesel would prove to be anexpensive option.

Gas propellants could be buy-back gas or nitrogen. The use of air in hydrocarbon lines would not be acceptable because of the associated safety risk. Buy-back gas is readily available and inexpensive whereas nitrogen is the opposite. A typical 2,000-gallon storage tank provides 150 MSCF of useable nitrogen. For a 30-mileround trip pigging operation through 6- inch ID flowlines, approximately 8,580 MSCF of nitrogen would be required based on a pigging pressure of 2,000 psi.This volume would be equivalent to approximately 57 tanks of nitrogen. The logistics associated with procuring and operating this arrangement would prove overwhelming. The alternative is to use a nitrogen generator. However, this option is expensive to rent or purchase and represents significant equipment spread. Therefore, nitrogen is deemed only suitable for short tieback distances where volumetric requirements are not significant.

Pump Rating

The pressure rating of a pump for solids removal (i.e. wax) can simply be calculated by combining separator pressure, fluid friction, wax friction and pig


H-0806.35 19-38 1-Dec-00

drive pressure. For the majority of configurations, no static head requires to be considered since flowline is balanced.

Fluid friction can be estimated using Darcy-Weisbachs equation. The drive pressure for the pig can be estimated from a rule of thumb method as used by pig vendors. Refer to Figure 19-13. The wax friction component depends upon many variables (thickness, volume, strength, consistency etc) and this makes prediction extremely difficult. However, to take some account of the wax friction component, a pressure drop of 25 to-50 percent of the calculated fluid friction is proposed.

Pd = Pf + Pp + Pw+ Ps

where:

Pd = pump discharge pressure, psia

Pf = fluid friction pressure, psia

Pp = pig drive pressure, psia

Pw = wax friction pressure, psia

Ps = separator pressure, psia

INT

EC

EN

GIN

EE

RIN

G, I

NC

.D

EE

PST

AR

MU

LT

IPH

ASE

DE

SIG

N G

UID

EL

INE

H-0

806.

3519

-39

1-D

ec-0

0

Figu

re19

-12:

Typ

ical

DP

Req

uire

d to

Dri

ve D

iffer

ent T

ypes

of P

igs


H-0806.35 19-40 1-Dec-00

The minimum flowrate capacity of the pump should be rated to ensure that the pig travels at above 3 ft/s. If the pig is used in a cleaning application, then pig bypass (refer to section 19.7.3) requires to be considered. For wax cleaning a bypass of 5 percent is proposed.

Qd = 1.05 x Vp x Af

where:

Qd = pump discharge flowrate, ft3/s

Vp = pig velocity, ft/s

Af = flow area, ft2

Assuming the pump has an efficiency of 70 percent, the pumping powerrequirements can be calculated as follows:

Wp = Qd x Pd x .262

where:

Wp = pump power, hp

= pump efficiency

To enable the possible remediation of a stuck pig or wax blockage throughpressurization, it would be prudent to consider rating the pigging pump to match the maximum allowable operating pressure of the flowline.

Compressor Rating

The rating of a compressor for multi-phase flowlines is best determined from transient modeling. The drive pressure and flow is mainly dependent on the liquid hold-up within the flowlines and back pressures that may exist for a particular pig operating mode (i.e. driving against well production or separator).

As an alternative to transient modeling, a simple approach to approximatingcompressor rating is outlined below. This approach considers a round trippigging configuration for wax removal, where the host is located in shallow water


H-0806.35 19-41 1-Dec-00

and the subsea facility (i.e. subsea manifold and trees) is located in deepwater.Although well production may be used to return pig once it has traversed the manifold pigging loop, it is considered prudent to size the compressor based upon propelling the pig completely around the circuit. Production during this operation is shut in and flowlines are set at separator pressure. Assuming productioninvolves wet gas, the flowlines will contain X barrels of liquid hold-up that accumulates at the lowest point in the system (i.e. subsea manifold).Approximate values for liquid hold-up can be taken from steady state or transient calculations.

Because of the gas, liquid, wax and pig drive pressure components, and the configuration of the system, the compressor load will vary during the pigging cycle. A typical pressure profile against round trip pigging distance is shown in Figure 19-14.

The liquid friction component can be estimated using Darcy-Weisbachs equation. The length component is equivalent to the length of line that the liquid hold-uprepresents and the flowrate is equivalent to a pig speed of 3 ft/s. The gas friction component can be estimated from general equations found in the Engineering Data Book compiled by the Gas Processors Supplier Association (GPSA). The pig drive pressure can similarly be estimated as outlined previously. If wax is present, it is proposed that the wax friction component be equivalent to 25-75percent of the liquid friction component. Without calculating the total pressureprofile per pigging distance, a conservative approach to determining compressor rating is proposed, that combines the maximum value of all components.

Pd = Pfl + Pfg + Psl + Pp + Pw+ Ps

where:

Pd = compressor discharge pressure, psia

Pfl = liquid friction pressure, psia

Pfg = gas friction pressure, psia

Psl = static liquid pressure, psia

Pp = pig drive pressure, psia

Pw = wax friction pressure, psia


H-0806.35 19-42 1-Dec-00

Ps = separator pressure, psia

The flowrate of the compressor should be rated to ensure that the pig travelsabove 3 ft/s at rated discharge pressure.

Qd = Pd Ta Vp Af Za 0.0864

Pa Td Zd

where:

Qd = compressor discharge flowrate at standard conditions, mmscfd

Vp = pig velocity, ft/s

Af = flow area, ft2

Pd = compressor discharge pressure, psia

Pa = ambient standard pressure = 14.73 psia

Ta = ambient standard temperature = 520 R

Td = compressor discharge temperature, R

Za =compressibility factor at standard conditions

Zd =compressibility factor at discharge conditions

The power rating of the compressor can be determined from the followingformula.

Wc = 0.0857 [ ]

11

1 k

k

s

dsav P

Pkk

ETQZ

Where:

Wc = Compressor brake horsepower, bhp

Q = Compressor flowrate, mmscf

Ts = Suction Temperature, R

Zd = Discharge Compressibility factor


H-0806.35 19-43 1-Dec-00

E = Efficiency

High-speed reciprocating units use 0.82

Low-speed reciprocating units use 0.85

Centrifugal units use 0.72

= Polytropic efficiency

k = Ratio of gas specific heats, Cp/Cv

Ps = Compressor suction pressure, psia

Pd = Compressor discharge pressure, psia

Zav = (Zs + Zd)/2

Figure 19-13: Typical Pressure Profile for Round Trip Pigging Multiphase Flowlines

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 10 20 30 40 50 60

Typical Round Trip Pigging Distance (miles)

Typi

cal R

ound

Trip

Pre

ssur

e Pr

ofile

(psi

)

Pig DriveLiquid FrictionGas FrictionWax FrictionLiquid Static

SeparatorTotal Pressure


H-0806.35 19-44 1-Dec-00

19.7 System Operating Requirements

19.7.1 Monitoring & Assessment

To assist in optimizing pigging frequency and assessing pig performance,arrangements should be made to monitor the pipeline system before, during, and after each pigging operation. As a minimum, the inlet and outlet pressures, flowrates and temperatures should be measured and recorded.

If a supervisory control and data acquisition (SCADA) system is installed and combined with a computer model of the pipeline, then the pigging operation can be monitored and assessed on a real time basis. The system will continuallycompare the readings from reliable pressure transducers, flowmeters, andtemperature sensors against those calculated by the computer model. Anysignificant deviation from established limits between the measured and calculated parameters would result in an alarm or warning signal. The operator would then be in a position to implement remedial action to prevent a stuck pig or if a pig should stick there would be enough data available to estimate the location of the pig. The SCADA and computer model could also be used to assess the hydraulic performance of the flowline before and after any pigging operation. This would assist the operator in deciding whether or not changes were required to operating procedures, chemical treatment program, pigging strategy etc.

In addition to monitoring the pigging operation, relevant information should be collated to produce a comprehensive record of each pigging run. Typicalinformation that should be collated is as follows:

Launch and receive dates and times

Numbers and types of pigs launched and received

Drawings of the pigs with overall dimensions and seal/cup spacings

Line conditions during each pig run, including problems and unusual pressure

fluctuations

Conditions at the receiver after the pig run, such as the quantity and type of

debris, conditions of the pig, and resulting pressure drop

Launcher and receiver trap dimensions and connections


H-0806.35 19-45 1-Dec-00

A map and schematic of the pipeline showing its route along with key features

such as valves, bends, branch connections, and diameter changes

19.7.2 Speed Control

Pigs are most effective when running within an optimum speed range. For solids and liquid removal this range is 3 to 7 ft/s. At speeds below 3 ft/s, the pig may run in a series of start and stop motions, especially if gas driven. Also, at low speeds, the turbulent effect ahead of the pig will diminish resulting in removed solids falling from suspension. As the solids settle, they will accumulate in front of the pig and eventually lead to line blockage.

At higher speeds, there will be greater wear of sealing and scraping elements. If speed is too high, the pig will tend to ride over the deposits or if there is substantial volumes of liquid present, hydroplaning may occur. When highspeeds are experienced in a gas-pig-gas arrangement, then frictional heating and consequent breakdown of the polyurethane components is possible. Research has shown that as speed increases, the differential pressure increases.

Speed control of pigs propelled by liquid is relatively straightforward since it is directly proportional to the volumetric output of the separator or pump. For pigs propelled by gas, speed control is more complicated since it is affected by several variables (i.e. gas compressibility, line conditions, operating mode etc.).

For gas export lines, where pig speed is essentially determined by on-stream flow conditions set by the separator or compressor, the speed if excessive, can be reduced using pig by-pass. This involves creating a passage through the pig for the gas propellant to flow. This method not only improves pig performance but reduces the peak liquid slug rate that arrives ahead of the pig. This enables the operator to use smaller and more economical separators or slug catchers. Field tests performed on a 20- inch two-phase line, demonstrated that a 10% bypass produced a reduction of 70 percent in liquid arrival rate. As well as slipping the pig within the drive medium, by-pass also enhances cleaning performance. This is discussed in the next section 19.7.3.

In multi-phase lines of reasonable liquid content, speed control under gaspropulsion may be achieved by regulating the delivery rate of the liquid column ahead of the pig. This assumes that operating conditions permit the pig to produce a homogeneous liquid column ahead of itself. If the multi-phase line is


H-0806.35 19-46 1-Dec-00

predominantly of the gas phase with minimum liquid hold-up, the operator could still implement the latter speed control method by introducing a slug of liquid into the flowline prior to the launch of the pig. Another method for controlling speed under gas propulsion is to operate at higher pressures and maintain a reasonable level of backpressure on the pig. If the pig should stick during operation, then instead of packing the flowline and increasing the pressure via the compressor, the backpressure could steadily be reduced to initiate controlled pig movement.This procedure should help mitigate the high-speed pig excursions that are normally associated with gas propulsion. Also, higher backpressures would be advantageous when pigs are launched from deepwater hosts. The greaterbackpressure would limit the differential across the pig and hence the speed during transit down and up the steep risers.

19.7.3 Bypass

To improve the performance of cleaning pigs some form of pig bypass isrecommended. Bypass involves using the differential pressure across the pig to create fluid flow from rear to the front of the pig. The stream of fluid that flows through the pig not only washes the cleaning elements but creates a region of turbulence ahead of the pig. This region of turbulence is conducive in maintaining removed solids in suspension. If the removed solid is not held in suspension then it can settle and accumulate as a plug in front of the pig. Bypass provides lubrication and enables the pig to slip in the fluid drive stream so that the deposits removed can float away in the faster flowing stream in front of the pig.

Mandrel cleaning pigs have the bypass designed such that flow enters the pig from rear via ports, flows past the cleaning elements, and then exits the front via other ports. For foam pigs and mandrel pigs without ports, bypass is between the surface bearing area and the pipe wall.

The amount of bypass is specified as a percentage of actual bypass area to the equivalent area of the flowline internal diameter. Pig vendors have recommended a range of 3 to 5 percent. If bypass exceeds 5 percent then there is a risk the pig may install, especially if gas propelled

19.7.4 Solids Handling

Providing removed solids remain in suspension in front of the pig, then the solids when it arrives at the host should travel through the process equipment trouble free. However, there may be occasion where the solids could compact within


H-0806.35 19-47 1-Dec-00

reduced bore sections (i.e. shell and tube line heaters). If this blockage is not timely alleviated then it could possibly extend upstream beyond the hostshutdown valve, and therefore affect the operation of this valve and compromise system safety.

To mitigate this condition, the contents of the pigged flowline could be diverted into a dedicated test separator. This would leave the host separator (solids free) to handle well production. The test separator would also provide the means ofdirectly assessing the type and quantity of solids being removed per pigging operation. This would provide valuable information for optimizing the pigging strategy. To minimize cost, the test separator should only be employed when there is high uncertainty associated with the contents of the line (i.e. early or infrequentpig runs, change of production conditions, etc.). Another possible method to handle solids and avoid blockages would be to incorporate injection points for introducing chemicals or compressed air at strategic locations on the hostreceiving facility.

19.7.5 Operator Training and Manual

An essential part of successful pigging is the training of operator personnel. Without the correct training, there is a high risk that inappropriate action may be taken that not only compromises the pigging operation but system production and the safety of personnel. Simple but detailed operating procedures that cover every aspect of the pigging operation are required.

19.7.6 Tracking & Location

To ensure pigging operations are conducted in a safe and effective manner, some method of tracking pig passage is required. In its simplest form, this comprises mechanical indicators permanently installed on the launcher and receiver.Verification that a pig has left the launcher or arrived at the receiver will enable for the loading or removal operations to be safely performed.

When pigging lines for the first time or lines that have been pigged infrequently, there is a high risk that pigs may become stuck. Therefore, pig tracking in these situations becomes more critical, especially in deepwater lines, if the time and expense associated with locating a stuck pig is to be minimized. Moresophisticated tracking methods other than mechanical indicators are required.The following br

19 pigging

Documents

pigging requirementsfrom

feasibility of pigging

subject of pigging

single flowline pigging

pigging experience available

operation of pigging

platform wells

perspective of flow