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Copyright 2004, Offshore Technology Conference

This paper was prepared for presentation at the Offshore Technology Conference held inHouston, Texas, U.S.A., 36 May 2004.

This paper was selected for presentation by an OTC Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Offshore Technology Conference and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect any posi-tion of the Offshore Technology Conference or its officers. Electronic reproduction, distribution,or storage of any part of this paper for commercial purposes without the written consent of theOffshore Technology Conference is prohibited. Permission to reproduce in print is restricted toan abstract of not more than 300 words; illustrations may not be copied. The abstract mustcontain conspicuous acknowledgment of where and by whom the paper was presented.

Abst ractOrmen Lange is a gas field located 100 km off the Norwegiancoast in water depths varying between 850 and 1,100 meters.The selected development scenario for Ormen Lange is a sub-sea tie-back to an onshore processing facility at Nyhamna.

The field is located in a prehistoric slide area with varyingwater depths, from 250 to 1,100 meters. The result of this sub-sea slide is an extremely uneven sea bottom with local sum-mits 60 to 80 m high. The back wall of the slide is steep, up to26 degrees. Environmental conditions are also challenging.

This paper describes the flow assurance challenges andtechnical solutions selected due to the harsh environmental

conditions specific to the Ormen Lange development, includ-ing: Rough seabed combined with long tie-back distance. Sub-zero temperatures (-1 oC).

All together, this makes the Ormen Lange project one ofthe most challenging field developments worldwide with re-spect to flow assurance.

IntroductionThe Ormen Lange field, discovered in 1997, is located off-shore Norway approximately 130 km west-northwest of Kris-tiansund. The field covers an area approximately 10 km by44 km. The reservoir is located at a depth ranging from

2,650 m to 2,915 m below mean sea level. Recoverable re-serves are estimated to be approximately 375 billion Sm 3 gasand 22 million m 3 condensate. The intitial reservoir pressure is290 bara, and the reservoir temperature ranges from 86 to93 oC.

The field is located within a prehistoric slide area, the Sto-regga slide, with water depths varying from 850 to 1,100 m inthe planned development area. The seabed in the Storeggaslide is extremely irregular with soil conditions varying fromvery stiff clay with boulders to soft clay.

The selected development concept for Ormen Lange con-sists of a subsea tie-back to a shore terminal as shown inFig. 1. The shore terminal will be located at Nyhamna, close

to the city of Molde. The gas will be produced from up to 24subsea wells. The well fluid will be transported to the landterminal through two 30 multiphase lines. After processing,the dry gas will be transported from the land terminal througha new 42pipeline to Sleipner and from there through a new44 pipeline to receiving facilities in Easington, UK.

The annual gas export plateau will be approximately21 billion Sm 3 and the daily export capacity up to 70 mil-lion Sm 3.

To maintain production when reservoir pressure declines,an offshore compression facility is planned for installation inthe field with a planned start-up date in 2016. However, a sub-sea compression solution will be evaluated, in parallel, as acost-effective alternative to a compression platform.

Field development and subsea system architectureDue to the wide geographical extent of the Ormen Lange field,the risk of experiencing a segmented reservoir and, in addi-tion, limitations with respect to long reach well/high deviatedwells, the subsea architecture requires a high degree of flexi-

bility. A phased development scheme has been selected for thefield. The completion of subsea wells will be timed to main-tain plateau production as the field depletes.

Initial development. The initial subsea development will con-sist of two 8-slot production templates (A & B), located ap-

proximately 4 km apart in the main production area as shownin Fig. 2. There will be dual 20 production headers on eachtemplate that will be tied into the two 30 multiphase pipelines

by means of rigid spools. The two 30 lines will be connectedvia a pipeline end termination system (PLET). Two main con-trol umbilicals will link the onshore plant to the subsea pro-duction system; one will be connected to template A, and theother to template B. A crossover control umbilical will inter-connect the two production templates, providing redundant

control of all the subsea wells. The capability for round-trip pigging of the 30 multiphase pipeliens is provided by instal-lation of a pigging loop.

For prevention of hydrate formation, all wells are continu-ously dosed with monoethylene glycol (MEG) supplied viatwo 6 pipelines from the shore terminal. One line will beconnected to template A, and the other to template B. A 6crossover MEG line will interconnect the two production tem-

plates providing redundant supply of MEG to the templates.Each 6 MEG line has sufficient capacity to supply the MEGrequirements of all the wells in the field.

OTC 16555

Ormen Lange - Flow assurance challenges Arild Wilson, Sverre J Overaa, Henning Holm / Norsk Hydro ASA, Norway

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Future development. A further development of the OrmenLange field may take place in the future depending on the pro-duction experience from the initial phase. The scenario fore-seen for the future extension of the field is shown in Fig. 3 andis comprised of two additional 6-slot production templates (C& D). The future 6-slot templates will each include two sparewell slots that may be used for additional wells. Each of these

production templates will produce gas through dual 12 mani-fold headers and infield flowlines tied back to the 30 PLET(valid for template C) and hot-tap tees in the 30 lines (validfor template D). A new infield 6 MEG line will be connectedto each of the two future templates (C and D) as extensionsfrom the initial templates A & B. Similarly, new infield con-trol umbilicals will be connected to each of the two templates(C and D) as extensions from the templates A & B. See /2/ forfurther details.

Well completions. The initial development will include 8 of9-5/8 hybrid well completions with 7downhole safety valves(DHSV) and horizontal Xmas trees. The remaining well com-

pletions are assumed to be 7 completions with identical Xmastrees as for the initial wells. See /3/ for further details.

Future compression . The concept will allow for tie-in to afuture pre-compression platform or a subsea compression unit.The system will include subsea tie-in points applicable for

both a platform and a subsea gas compression solution. How-ever, the initial subsea control system and control umbilicalswill not include any facilities for signal or power for a futuresubsea compression facility. See /4/ for further details.

Ormen Lange specific flow assurance challengesThe key Ormen Lange specific environmental conditions chal-lenging flow assurance are: Rough seabed. Sub-zero temperatures (-1 oC).

Rough seabed. The gas field is situated in 850 m water depthin an area of a prehistoric subsea slide, the largest known todate. The result of this slide is an extremely uneven sea bot-tom with local peaks, 60 to 80 m high. The back wall of theslide area is very step, up to 26 degrees. The rough seabedtopography combined with the 120 km tie-back distance to theonshore processing facilities stretch the limits of current mul-tiphase flow technology.

Correct modelling of the detailed seabed and pipeline to- pography and reliable multiphase flow models are imperativefor the Ormen Lange development, and will be discussed be-low.

Correct calculation of pressure drop is a requirement forhydraulic capacity and line-sizing/liquid holdup manage-ment/compression requirements.

Correct prediction of liquid holdup is important for pres-sure drop calculations, operational flexibility and slugcatcherdesign.

Sub-zero temperatures. The other Ormen Lange specificen-vironmental challenge is the sea water temperature of minusone (-1) degree Celsius, which creates the risk of ice formationin addition to the risk of hydrate formation. As a result, there

has been intensive discussion on the risk of hydrate/ice plugs, physical characteristics of the plugs, methods for preventionand remediation of potential hydrate/ice plugs.

The low hydrate equilibrium pressure at seabed tempera-ture, combined with the rough seabed topography, challengesdepressurization as a means for hydrate remediation, as thehydrates may convert to ice during depressurization.

All together, this makes the Ormen Lange developmentone of the most challenging field developments worldwidewith respect to flow assurance.

Hydrate management

Hydrate and ice formation. Due to the low seabed tempera-ture, both hydrates and ice may form, unless the fluid is suffi-ciently inhibited. Experiments have shown that the uninhibitedOrmen Lange well fluid has a high potential for hydrate for-mation in continuous flow mode as well as during shut-in, andthe hydrates have a high tendency to deposit on the pipe walls.The hydrates appear to be sticky and the plugging potentialseems to be high. Therefore a basic assumption is that the un-inhibited Ormen Lange well fluid very easily forms hydratesand ice and that the plugging potential is high.

Primary hydrate prevention strategy. Prevention of hy-drate/ice formation is given high priority, as removal of hy-drate/-ice plugs may be complicated.

The overall Ormen Lange hydrate prevention strategy is tominimize the risk of operation within the hydrate region.

This is achieved by continuous MEG injection at the indi-vidual wellheads. Each well will be equipped with a dosagesystem. The MEG distribution system will be designed with acapacity to inhibit the maximum expected condensed water

plus formation water/gas production from individual wells.MEG delivery requirements for each well will be individuallydetermined based on water production predictions from eachwell. Measurements of water production using wet gas meter-ing technology will be used as a backup to water production

predictions. A safety factor will be used to ensure adequateMEG injection, taking into account the water prediction andmeasurement accuracy.

The MEG injection/distribution system will be designedwith respect to high availability/reliability/redundancy tominimize the risk and consequences of failure of individualsystem components, and to minimize the risk of hydrate for-mation and the need for hydrate remediation.

Dual 6 MEG supply lines from shore, each with 100%

overcapacity, will be installed to increase availabil-ity/reliability/redundancy and to provide capacity for overdos-ing to reduce the hydrate risk due to MEG injection systemfailure (uncertainty, mechanical, operator error).

MEG injection requirements. The hydrate suppression re-quirement is a hydrate temperature of 5 oC at maximum po-tential pipeline shutin pressure (255 bara). This corresponds to60 wt% MEG in the aqueous phase.

The MEG injection and regeneration system will be de-signed for saturation water only, combined with up to 50Sm3/sd of formation water (maximum). The total MEG injec-tion capacity is 1,500 Sm 3/sd.

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The following assumptions have been made in predictionof the condensed water: The produced gas will always be saturated with water at

in situ reservoir conditions (P&T). The gas water saturation is expected to increase during

the lifetime of the field due to the reservoir depletion.

MEG injection and distribution system. The subsea MEGinjection and distribution system is designed with high focuson availability/ reliability/ redundancy to minimize the riskand consequences of a hydrate prevention failure, and conse-quently the risk of hydrate formation and the need for hydrateremedial actions.

MEG delivery requirements for each well will be individu-ally determined based on predictions of water production fromeach well. A safety factor will be used to ensure adequateMEG injection, taking into account the water measurementaccuracy (+35% has been applied for design purposes), anduncertainties in the MEG distribution and control (+20% has

been applied for design purposes).

The following requirements have been defined for de-sign/operation of the subsea MEG distribution system from aflow assurance perspective:1) Line pressure in MEG distribution system will be at asuffi-

cient margin above maximum wellhead shut-in pressure to prevent backflow of wellfluid into the MEG system and toensure MEG injection into the well(s) with the highestwellhead pressure at any flowrate including no-flow condi-tions.

2) The line pressure and pressure drop across the subseaMEG dosage system will be sufficient to minimize impactof pressure transients and interaction between wells.

3) Frictional pressure drop in the MEG supply lines will beminimized to avoid transients and significant interaction

between wells during operation of either the production orthe MEG injection system.

4) The Xmas tree system will be equipped with two MEGinjection points:i. During normal production MEG will be injected

downstream PWV / upstream the choke to ensuregood mixing.

ii. During valve integrity testing, pressure equalization prior to start-up, bull heading and well treatment fol-lowing shut-in, MEG will be injected between thePMV and PWV.

5) Each well will be equipped with a distribution system/logicthat ensures that sufficient MEG is injected into each indi-vidual well.

6) Due to the varying reservoir depth and correspondingchange in the reservoir temperature and water saturation,the required MEG injection rate to inhibit the water satu-rated well fluid needs to be calculated individually for allwells based on individual well bottom hole pressure andtemperature.

7) The control of the MEG dosage unit will, as a minimum,have 5 positions to control the MEG injection rates. Thesize/flow performance of the 5 positions will be optimizedduring detailed design and verified by experimental flowtests.

8) Provisions shall be made to prevent backflow of wellfluidfrom the production bore into the MEG injection system.

9) The dosage unit will as far as practically possible be de-signed to minimize the risk of particle accumulation result-ing in clogging of the dosage unit (smooth geometry withno abrupt geometry changes, no cavities, etc.). The l/d ra-tio of the hole sizes should be maximized to achieve as big

hole sizes as possible, and in-situ flushing/cleaning of theMEG dosage unit will be possible.10) The subsea system will be protected from over pressuriza-

tion by the MEG injection pumps in the event of a pump-trip or a shutdown of the MEG system.

11) It will be possible to use the MEG dosage unit as a com- bined flow control and backup flow measurement devicewith accuracy better than 10%, i.e., a position indicator is

provided.12) A dedicated computerized MEG monitoring system will

be developed to monitor the integrity (e.g., leak-age/blocking) and performance of the subsea MEG distri-

bution system, and ensure that sufficient MEG is injectedat all times to inhibit the production templates and 30"multiphase export pipelines to shore.

Risk of hydrate and ice formation. The risk of hydrate pre-vention failure and the risk of getting a hydrate plug have beenevaluated through both availability analysis and fault-treeanalysis. The work has focused on normal operation of the two30 multiphase production pipelines. The model has been usedto identify critical contributors, and to improve system designand operational strategies to reduce the risk of hydrate forma-tion.

A simplified schematic of the fault tree analysis is illus-trated in Fig. 7.

The main contributor to the risk of forming a hydrate plugis MEG injection failure/ insufficient MEG inhibition. Thefault-tree analysis indicates that a hydrate prevention failureresulting in insufficient MEG inhibition in one of the two 30multiphase production pipelines may exist approximatelyevery 250 years given formation water breakthrough will oc-cur, and every 450 years given water break through will notoccur. However, given insufficient MEG inhibition, develop-ment of a critical hydrate plug that cannot be removed by de-

pressurization requires the following additional conditions to be in place (see Fig. 7):1) Continued operation in hydrate conditions (e.g. pressure

and temperature).2) Conditions for forming sufficient hydrates to plug the line

(e.g. water and time).3) Inability to remove the plug by depressurization.

Hence, critical hydrate plugging would occur at frequen-cies less than indicated since the probability that these otherconditions required for hydrate plug formation to occur willalso be considered. It should be noted that the subsea produc-tion system and the deepwater part of the multiphase produc-tion pipelines still may operate outside hydrate conditions dur-ing flowing conditions, even with an uninhibited wellstream.

Table 1 shows the risk of forming a hydrate or ice plug inone of the two multiphase production pipelines for differentcombinations of high, medium and low conditional

probabilities. It is stressed that values of the high, medium

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and low conditional probabilities are only for illustration purposes. The results are based on normal production during30 years production time.

Table 1. Risk og forming a hydrate or ice plugMTTF

(MEG

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hydrate remediation. This area is analogue to most other longdistance, gas/condensate tiebacks.

The Ormen Lange specific challenges with respect to hy-drate/ice plug formation/prevention/remediation are in thelower part of the escarpment, located in deepwater and sub-zero temperatures.

Plug location. Potential hydrate/ice plugs may form eitherduring flowing or no-flowing conditions: Flowing condition . During flowing conditions, plugs that

form are most likely due to:MEG injection failure / operator failure.Undetected formation water breakthrough.The most likely plug location is the upper part of escarp-

ment where the flowing temperature drops below the in-situhydrate temperature of the under-inhibited wellfluid. The hy-drate temperature and the corresponding most likely plug loca-tion is thus a function of the in-situ MEG concentration, andthe production rate/temperature profile as illustrated in Fig. 5.

It should be noted that the seabed temperature in this areais above the ice formation temperature, and that the risk ofgetting an ice plug that cannot be removed by depressurizationis low.

No-flowing conditions. During no-flowing conditions, plugs that form are most likely due to:

Commissioning/tie-in of new in-field flow lines. Water ingress (cold sea water or commissioning fluids)

into no-flowing conditions. MEG injection failure during start-up.

The most likely plugging location is in the areaswithin/close to subsea production systems, i.e. in the area ex-

posed to sub-zero temperatures. However, in this situation itcan be assumed that the fluid in the multiphase production

pipelines is sufficiently inhibited.

Risk of ice formation. Experiments with uninhibited gas haveshown that hydrates convert to ice during depressurization atsub-zero temperatures.

One of the key project findings is that the presence ofMEG, even at a fraction of the required injection rate, will

prevent ice formation and facilitate hydrate melting even at theworst case expected pressures. Studies showed that depres-surization may be used in deepwater with sub-zero tempera-tures if the fluid is partly inhibited with MEG. The presenceof MEG, even at a fraction (

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the MEG. However, if the hydrate plug resides in a gas-filledsection of the flow line, the ice will not melt. Such a situationcould occur if a hydrate plug forms in an upward bend (re-versed dip), and the liquids drain away from the plug immedi-ately after the blockage occurs. Probably, the risk for this hap-

pening is not too large, but it cannot be fully excluded. As aresult, the Ormen Lange project has investigated several op-

tions for secondary hydrate remediation.The secondary hydrate remediation strategy selected forthe Ormen Lange multiphase production lines is flow-line/pipeline replacement.

Restart after hydrate remediation. Prior to restart after ahydrate plug has been remediated, the uninhibited fluid in the

plugged pipeline will be either replaced or inhibited. This can be done in two ways:

Roundtrip pigging at low pressure may be carried out toremove under-inhibited liquid. A huge batch of MEG isinserted in front of the pig. Dry gas inhibited with MEGwill be used as the driving medium.

Circulating dry gas combined with MEG injection tosweep out uninhibited fluid. MEG is injected both onshoreand subsea. First the rate is adjusted to sweep out uninhibi-ted fluid. Afterwards the rate is decreased to establish asufficient MEG holdup in the system.

Gas is provided by back-flowing dry gas from the export sys-tem from the onshore plant.

Hydrate prevention prior to initial start-up. All subseaequipment will be filled with MEG inhibited water prior to or

just after installation to avoid hydrate formation due to gasleaking valves. MEG supply lines will be filled with MEG

prior to or just after installation to avoid hydrate formation andto eliminate concequences of erroneous injection of uninhibi-ted water into well fluid due to design, procedure or operatorerrors. MEG will be distributed along the flow path from thewells to the onshore plant, prior to initial well start-up.

Corrosion management

Corrosion protection and material selection multiphasepipelines. The reservoir fluid of the Ormen Lange field con-tains mainly gas. Due to a relatively high CO 2 content and the

presence of condensed water inside the pipeline, the corrosiv-ity is relatively high. In order to accept carbon steel as pipelinematerial, the injection of chemicals is necessary to reduce thecorrosion rate to an acceptable level. In the first phase of pro-duction, before any formation water is present in the wellfluid, injection of a pH stabilizer (NaHCO 3 or possiblyKHCO 3) is planned. This will increase the pH in the well fluidand thus reduce the corrosion rate down to about 0.1 mm/year.After the appearance of formation water, the method of corro-sion control must be changed. The pH of the MEG must bereduced to avoid scale formation. Corrosion will then be con-trolled by the injection of a film-forming corrosion inhibitor atthe X-mas trees to reduce the corrosion rate to below0.1 mm/y. A qualification program is underway to qualify asuitable corrosion inhibitor.

Due to the low sea temperature in the Ormen Lange area,top-of-line corrosion is expected in the first part of the pipe-

line downstream from the templates. To reduce this phenome-non, the external pipeline coating (FBE + PP) will be in-creased to 8 mm to reduce the condensation rate on the inter-nal pipe wall and thus reduce the top of the line corrosion rateto an acceptable level (about 0.1 mm/y). Hence, a corrosionallowance of 10 mm for the warm part of the pipeline and7.5 mm for the cold part of the pipeline is specified to obtain

the 50 years design lifetime for the multiphase pipeline. Thisalso includes a safety margin of 0.1 mm/y.Since no signs of H 2S have been detected in the well

analyses, sour service has not been specified for the pipelinematerial.

Multiphase flow

Linesizing strategy. Two 30 pipelines have been selected toutilize a total hydraulic capacity of 60 to 70 MSm3/sd at areasonable pressure drop, to minimize compression require-ments and postpone compression requirements as much as

possible.In addition, one of the key line-sizing criteria has been to

achieve a large degree of operational flexibility, i.e. turndownflexibility in each of the two multiphase export pipelines with-out mitigation actions such as dynamic pigging or gas circula-tion.

A dual pipeline system is selected compared to one single,large pipe diameter pipeline both for in-field flowlines andmultiphase export pipelines to: Increase flexibility with respect to liquid holdup manage-

ment and turndown capability to facilitate sufficient turn-down, ramp-up and swing flexibility according to com-mercial/operational requirements.

Enable production through only one line at low productionrates.

Allow dynamic pigging by periodically increasing the production rate through one line at a time to sweep out liq-uid.

Reduce slug volumes/liquid surge volumes during transientoperations (start-up after shutdown, increasing productionrates) and minimize required slugcatcher size.

Enable circulation of dry gas to increase flow velocitiesduring low turndown (subsea gas lift).

Increase flexibility to remove potential hydrate plugs (de- pressurization from two sides or increased availability dueto production through one line if the other line is blocked

by hydrate plug). Increase regularity/production availability in case hydrates

blockage /failure in one line. Simplify pipeline installation in deepwater (smaller diame-

ter). Maximum pipeline / riser dimension is limited by in-stallation in deepwater (30 nom).

Fig. 9 illustrates the typical performance of the 30 multiphase production lines at typical plant arrival pressures.

Liquid holdup management. The minimum turndown / op-erational envelope is defined by the declination point of theflow characteristic (friction dominated) pressure drop, but may

be extended by use of dynamic pigging to manage liquid(condensate and aqueous phases) holdup. However, it should

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Table 2. Model parameter sensit ivit yParameter Low Default High

Apparent roughness multiplier 0 1 5Interfacial friction factor multiplierfor steep angles

0.3 1 3.5

Oil-water interfacial friction multi-plier, stratified

0.25 1 4

Oil-water interfacial friction multi-plier, slug

0.5 1 2

Multiplier for onset point for mixingin slug

0 1

NOTES:1) From the field data and the Porsgrunn high-pressure data, it is concluded that the

apparent roughness is most probably too high and not too low. The high value of theapparent roughness multiplier is, therefore, regarded only as an illustration of thesensitivity with respect to this parameter, without any implications that the highvalue could be a reasonable value of the parameter.

2) The infinite value of the onset point for oil-water mixing in the slug body isequivalent to setting the mixing to zero independent of velocity.

The results are summarized in Fig. 11, and they indicatethat further improvements of the OLGA model seems to re-quire significant effort in the fundamental modelling, and thattuning of the correlation parameters alone is not sufficient.

References/1/ A. Henriksson, A. Wilhelmsen, T. Karlsen, Pipelines in harsh

environment, OTC 16557, 2004./2/ T. Bernt, Subsea Facilities, OTC 16553, 2004./3/ R. Hartmann, Production Drilling, OTC 16554, 2004./4/ B. Bjerkreim, Subsea Compression,OTC 16561, 2004./5/ G. Elseth, H.Holm, H.Kvandal, S.Munaweera, P.Duchet-

Suchaux, G.Coffe, W. Vandersippe, "High-Pressure Recom- bined Gas-Condensate-Water Flow at Inclined Conditions,"BHR 11th International Conference on Multiphase 03, SanRemo, Italy 2003.

/6/ H.Kvandal, S.Munaweera, G.Elseth, H.Holm, "Two-Phase Gas-Condensate Flow in Inclined Pipes at High Pressure," SPE77505, SPE Annual Tech. Conf. and Exhibition, 2002.

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Fig. 1. Field development overvi ew.

Fig. 2. Initial subsea development.

Fig. 3. Future subsea development.

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Ormen Lange specific challenge!

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Pileline prof ile

Most likely hydrate plug duringflowing conditions:

MEG injection failure /operator failure

Undetected formation waterbreakthrough

Most likely hydrate plug during no-flowingconditions:

Commissioning/tie-in new in-field flow lines Water ingress (cold sea water or

commissioning fluids) into no-flowingconditions

Fig. 5. Expected hydrate plug location during flowing / no-flowingconditions.

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Formation water, unconstrained (P50) (Sm3/sd)Condensed water (P50) (Sm3/sd)MEG+20% uncertainty, 60wt% (Sm3/sd)MEG wo uncertainties, 60wt% (Sm3/sd)

Fig. 6. Water production and MEG injection requirements duringlifetime of the field.

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