19099Canyon Express Slugging and Liquids Handling

8/8/2019 19099Canyon Express Slugging and Liquids Handling

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Copyright 2001, Offshore Technology Conference

This paper was prepared for presentation at the 2001 Offshore Technology Conference held inHouston, Texas, 30 April3 May 2001.

This paper was selected for presentation by the 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

position of the Offshore Technology Conference or its officers. Electronic reproduction,distribution, or storage of any part of this paper for commercial purposes without the writtenconsent of the Offshore Technology Conference is prohibited. Permission to reproduce in printis restricted to an abstract of not more than 300 words; illustrations may not be copied. Theabstract must contain conspicuous acknowledgment of where and by whom the paper waspresented.

AbstractThe Canyon Express development is a three operator

(TotalFinaElf, BP, and Marathon Oil Company) subsea

development consisting of the transport of gas-condensate

from deepwater (~7000 feet) subsea reservoirs to a host

platform via dual 47-mile 12-inch nominal OD flowlines.Thethree developments are Camden Hills (Marathon, Pioneer

Natural Resources USA, Inc., and TotalFinaElf), Aconcagua

(TotalFinaElf, Pioneer Natural Resources USA, Inc., andMariner Energy, Inc.) and Kings Peak (BP). The Canyon

Express development is unique in that it involves ultra-

deepwater reservoirs from three individual operators flowing

into a common subsea multi-phase gathering system in which

the operating pressure is lowered over time as dictated by

reservoir decline. The flowline fluid is predominantly methane

gas along with a liquid phase consisting of condensate,

produced water, and methanol (injected for hydrate

inhibition). To verify the operability of the system it was

necessary to perform transient simulations of the flowline to

predict the behavior of the fluid in the flowline.

The primary objective behind the transient simulations was

to determine the impact of the liquids in the flowline on thetopside facilities and evaluate system performance during both

upset and normal conditions. The software used to perform

these simulations was Scandpowers OLGA-2000 version

1.01. Scenarios and time points where potential problems due

to liquids were identified as well as appropriate techniques to

control the any associated liquid slugs. The results from this

work will form the basis of the operational procedures to be

developed for the Canyon Express flowline system.

IntroductionTotalFinaElf, BP, Marathon Oil Company, Pioneer N

Resources USA, Inc., and Mariner Energy Inc. int

jointly develop three deepwater fields in the Gulf of M

region. The fields are the Marathon-operated Camden HMississippi Canyon (MC) 348 block, TotalFinaElf-op

Aconcagua in MC305 block, and BP-operated Kings P

DeSoto Canyon (DC) 133 , DC177, and MC217 block

production consists primarily of methane gas with v

volumes of water and condensate. Methanol is to be inje

the wellhead for hydrate inhibition. Maximum prod

rates from each field range from 100 to 225 MMSCF

approximately 200 to 450 BPD of condensate, 300

BPD of water, and 450 to 1400 BPD of methanol.

The production from the wells will be transported v

12-inch nominal O.D. flowlines from the Camden Hil

at approximately 7200-foot water depth, to the Aco

field at approximately 7050-foot water depth, then to

Peak field at approximately 6600-foot water depth, and

to a host platform fixed structure located on the cont

shelf. The twin flowlines (East and West) form a pi

system via a loop connecting the two flowlines at the fl

ends. The flowlines are separated by a pigging valve,

will remain closed during the normal operation of the s

Thus, the flowlines will operate independently of the

Analysis of the flowline gas/liquid behavior under v

operating scenarios is required to establish and

operability. The flowline tie-ins of the individual wells

follows:

East Flowline

(2) Camden Hills (MC348-1, MC348-2)(1) Aconcagua (MC305-3)

(1) Kings Peak (DC177-2)

West Flowline(2) Aconcagua (MC305-1, MC305-2)

(3) Kings Peak (MC217-3, MC217-2, DC133-2)

The layout is shown schematically in Figure 1.

OTC 13073

Canyon Express Slugging and Liquids Handling

Bryan K. Wallace, Marathon Oil Company, Ravi Gudimetla and Geir Saether, Intec Engineering Inc.


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2 B. WALLACE, R. GUDIMETLA, G. SAETHER OTC

The operation of the Canyon Express production system

will consist of a gradual reduction in topside pressure over

time (Early Life Host Platform Arrival Pressure of 2000 psig

through to Late Life Arrival Pressure of 500 psig) to maximize

recovery from the wells. As the gas rate and reservoir pressure

decline over time, liquid loading in the wells and flowlines

will increase. As the liquid loading in the flowlines increase,

various production problems due to liquid slugging may occurduring both normal production and transient situations (system

restarts, flow increases, etc.) if liquids are not properly

managed. Thus, the handling and management of temporary

increased liquid flowrate and volume is a significant aspect in

determining the operability of the Canyon Express system.

The objective of this paper is to describe the dynamic

simulations, using OLGA 2000 version 1.01, performed to:

Determine the approximate range and duration ofincreased liquid flow expected over the field life for

different production scenarios,

Summarize the range of liquid volume computed

Identify specific scenarios during the field life where

liquid management problems arise.

Studied ScenariosWith input from the various Canyon Express partners, specific

steady-state and non-steady-state scenarios were identified for

dynamic modeling to predict slug volumes (if any) that could

be present with each specific scenario. The scenarios were

simulated for early (2000 psig arrival), mid (1000 psig arrival)

and late (500 psig arrival) field life conditions to show the

effect of increased liquid loading due to decreased flowline

pressure and water production. These pressures were used to

differentiate between the times in the field life are shown in

the Design Data and Assumptions section of this paper. In

addition, all simulations were performed for the East flowline

only as this line is expected to have lower gas flowrates,

higher water rates, and lower pressure which results in a

greater potential for liquids management problems.

The scenarios where significant variations in liquid

flowrate may occur are as follows:

Steady-State Operation (Low Flow). For normal operation

where the gas flowrate is too low to maintain steady flow,

liquid and pressure builds up in the flowline until the flowline

pressure is high enough to push the liquid slug out of the

flowline and onto the platform topsides facilities. For this

scenario, the liquid rate to the topsides would fluctuate due to

the cyclical loading and unloading of flowline liquid content.

As long as the HP Separator can adequately handle the liquidfluctuations, the operation could tolerate "slight slugging" but

not require any slug tank capacity. If the periodic slugs were

in excess of topsides liquid handling capability then the slug

tank must be sized such that the predicted periodic slug

volume could be contained thus allowing for continued

operation at the design gas flowrate. Modeling this scenario

also helped to evaluate the operating envelope of the

production system. The operating envelope involves finding

the lowest flowline production rate, at which the syste

operate without the creation of slugs whose size is great

the capacity of the topside facilities.

System Shutdown and Restart. This is indicat

situations where all wells on a flowline are shutdown

extended period and subsequently restarted. Durin

shutdown, liquids are expected to settle at low spots in tdue to gravity. Upon restart of the wells, these liquids

transported out of the flowline in the form of temporary

liquid flowrates. The analysis was centered on evaluati

increased liquidvolume and to determine ifthese slugs

excess of the liquid handling capacity of the topside faci

Increase of Gas Flow. This is indicative of bringing

on-line or increasing the flowrate from a well. For a c

host platform arrival pressure, the higher the gas flo

lower the steady-state liquid holdup in the flowline. As

flow from the wells is increased the flowline liquid con

reduced from the steady-state volume of the lower flo

with the shutdown and restart case, during the period inthe higher liquid content is being displaced there

temporary increase in liquid flow to the topsides. The

rapid the gas flow increase, the higher the liquid rate

topsides facilities. Therefore, an increase in gas flowrat

be limited to a rate that results in manageable liquid volu

Increase of Liquid Flow. An increase of associated

from one or more wells (e.g. increased water flowrate

breakthrough) will result in a higher steady-state

flowrate to the topsides facilities. If the liquid flow

excess of the topsides capacity then the high liquid cu

would need choked back as the slug tank is design

intended for transient liquid flow increases and not co

high liquid flows.

Pigging and Rapid Flowline Depressurization. Al

pigging and flowline depressurization were consider

evaluated in the design and are important fact

determining adequate topside facility capacity for

management, neither topic is discussed in this paper.

Design Data and Assumptions

Flowline Fluid Composition. Canyon Express hydro

fluid is predominantly methane (~99 mol%) with a

condensate in the quantity of 2 Bbls/MMSCF at stoc

conditions. Additional liquids in the flowline include prwater and methanol injected upstream of the choke a

wellhead for hydrate inhibition.

Flowline Route Profiles and Properties. The East fl

route profile, shown in Figure 2, was obtained directl

flowline alignment sheets. The flowline and riser o

diameter is 12.75-inches. The flowline wall thickness

based on mechanical requirements and codes.


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OTC 13073 CANYON EXPRESS SLUGGING AND LIQUIDS HANDLING

Reservoir Data. Each field operator in the Canyon Express

system has independently modeled their respective reservoirs.

For this work the specific reservoir data was compiled and

used as the basis for input to the transient simulations and for

evaluation of the results. Due to confidentiality issues, the

reservoir data are not stated in this paper. The parameters used

for input and evaluation include: water production per zone

over time, production rate over time, and correspondingreservoir pressure over time.

Flowline Fluid Rates. The basis for the transient simulations

cover conditions representing early life, mid life, and late life

flowline operation as outlined in Table 1. This covers an initial

host platform arrival pressure of 2000 psig, end of life arrival

pressure of 500 psig, and includes an intermediate operation

with an arrival pressure of 1000 psig. The liquid flow from the

individual wells assumed in the flowline during these periods

are consistent with the liquid predicted in the reservoir models

and steady-state flowline simulations :

The liquid flow values used in the simulations were

obtained from the steady-state simulations and thereservoir performance predictions provided from each

Canyon Express partner.

The host platform arrival pressures and predicted gasflowrates for each case were obtained from the steady-state

simulations.

Host Platform Topside Facilities. Included in the OLGA

dynamic simulation of the flowline was modeling of the HP

Separator operation and its respective outlet liquid flows.

Figure 3 shows the flow schematic diagram of the topside inlet

facilities for one of the two flowlines. The process flow path

of the production is summarized as follows:

The multi-phase flow from the Canyon Expressflowlines is routed to its respective inlet HP Separator.

The gas phase from the HP separators is compressedand dehydrated.

During normal operation, the separated liquidproduction flows from the Canyon Express two-phase

HP Separators to further liquid processing facilities.

This includes separation facilities for the water,

methanol, and condensate.

Any liquid from the flowline that flows into the HPSeparator in excess of its normal processing capacity is

routed to a 2400 barrel slug tank on the topsides.

The dynamic modeling performed with OLGA 2000

included simulation of the HP Separator operation and its

respective liquid outlet flows. This provided a prediction of

the effect and response of the host platform inlet separator and

its resultant normal flow to the downstream liquid facilities

and emergency flow to the slug tank. The topside modeling

portion of the flowline simulation, illustrated in Figure 3,

included the HP inlet separator only. To adequately represent

the normal liquid flow from the separator the normal outlet

flow was constrained to the capacity of the downstream

equipment. Any flow in excess of this constraint was routed to

an emergency dump (slug tank). The OLGA modeling

inlet separation did not permit application of a constr

the emergency dump liquid flowrate. Conformance

identified liquid flow constraints to the slug tank

confirmed and adhered to via iteration of the simulation

topside basis assumed for separator simulation is as follo

A normal liquid level was defined for the two-pha

Separator. A level of 1.25 feet above the normal lthe HP separator results in liquid flow to the eme

dump (slug tank). A 4" liquid level control valve

liquid outlet line was modeled and tuned to maint

normal liquid level setpoint. The emergency dump

when the HP separator liquid level reaches 0.05 feet

the defined normal level.

A maximum outlet liquid flow constraint from tSeparator was used to simulate the liquid ha

limitation of downstream facilities for liquid from th

flowline. Any flow above this value would result

liquid level rising in the HP separator. This fl

constraint differed for the three periods modeled

downstream facilities service both flowlines and thline liquid flow varies over time. The total liqui

constraint value used was consistent with the capa

the downstream liquid handling facilities.

The flow of liquid from the HP Separator to the sluvia the emergency dump is limited by a fixed

(installed to limit gas blowby) in the line. Constraint

flowrate on the emergency dump liquid within the

was not possible as this is not an OLGA capability

value was manually adhered to by verification fro

simulation output and modifying as necessary.

System Modeling and Analysis SummaryThe transient simulations for the Canyon Express system

performed using OLGA 2000 version 1.01. Data gen

from steady-state modeling was used as the initial inp

the transient model and the OLGA model was then ru

steady-state condition. Flowline operation was manipul

simulate both steady-state operation and the variou

steady-state scenarios described above to determi

ultimate effect of operational changes on flowline

loading and host platform topside facilities.

The following sections briefly summarize the sim

procedure and results for each of the scenarios. Critica

where significant slug volumes occur for a specific sc

are discussed in more detail within the respective section

Steady-State Operation Procedure and Summary

Simulation Procedure. The objective of these simu

was as follows :

Determine if flow instabilities due to sluggingduring the normal steady-state operation o

flowlines for various flowrates across the ra

potential operating conditions.


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If slugging were present at design production rates, then

flowline diameter, gas rates, and operating pressure would

need to be modified. The simulation procedure was to run at

various flowrates for a specific arrival pressure. Each

simulation continued until a steady-state condition was

reached. A steady-state condition was defined as when the

liquid content in the flowline remained constant or when

steady cyclic fluctuations were observed in the liquid contentand exit liquid rates as shown in Figure 6. The former is

indicative of higher flowrate conditions where liquids are

swept out of the line at constant rates due to the higher gas

sweeping velocity. The latter is indicative of increased liquids

production due to an increase in water production combined

with lower gas sweeping velocities.

Summary of Steady-State Operation Results.

The initial analysis concerning transient modeling was to

determine the flowline liquid content and flowrate for various

gas flowrates and pressures in the range of flowline operation.

Liquid management problems are generally observed at lower

gas velocities and higher liquid content resulting in higher

pressures at the wellheads and fluctuations in liquid rates atthe topsides. Figures 4 and 5 illustrate the resulting liquid

loading and wellhead pressure at different flowline outlet

pressures and produced water content.

Figure 4 shows the predicted liquid content in the flowline

for various gas flowrates in the Canyon Express operating

envelope. The graph illustrates the following:

Liquid content increases as the flow rates for each casedecrease as shown in the top graph.

Higher liquid contents are observed for the higherpressure cases compared to the lower pressure cases at

similar rates as there is less velocity in the flowline.

(e.g. 100 MMSCFD at 2000 psig arrival shows a 7000

barrel liquid content versus 5000 barrels for the 100

MMSCFD at 1000 psig case).

Operation at 20 MMSCFD for all three cases shows aliquid content of approximately 20,000 barrels.

Figure 5 shows the predicted wellhead pressure (end of

the flowline) for various gas flowrates in the Canyon Express

operating envelope. In general, a change in gas flow rate

affects the pressure at the end of the flowline. For dry gas, a

decrease in gas flowrate should result in a decrease in pressure

drop across the flowline. The graph illustrates the following:

For the Canyon Express multiphase flow a decrease ingas flowrate results in an increase in liquid content.

This additional liquid effectively reduces the cross-

sectional area of the flowline and creates pockets of

liquid and hydrostatic head that the gas must overcome.

At higher gas flowrates the pressure drop across theflowline decreases as gas flow through the flowline is

reduced. This is due to the relatively insignificant

change in flowline liquid content at these flowrates.

At lower gas flowrates the pressure drop across theflowline actually increases as gas flow through the

flowline decreases. This is due to a significant increase

in flowline liquid content at the lower gas flowrates.

The transition point between higher flowrates andflowrates (as illustrated by the inflection) can b

on the early life curve at 150 MMSCFD. This is

the flowline pressure drop moves from gas

dominant to liquid content dominant.

Figures 4 and 5 illustrate that lower gas flowrates

necessarily result in lower flowline pressure drop

resultant increase in liquid content at lower gassignificantly increases the pressure at the end of the flow

As ascertained from these graphs, flow instabilit

sudden liquid increase at the platform over time), is li

occur at low flowrates which might occur anytime durin

life. Thus analysis was performed to determine the

slugging potential and system operability for a range

flowrates. A summary of this analysis per time is as fol

Early Life. Theliquid flowrate was constant at thegas flowrates. Slight liquid fluctuations were observ

low gas flowrate of 20 MMSCFD but no liquid vol

excess of HP Separator capability was predicted.

Mid Life. The liquid flowrate was constant at the

gas flowrates. Slight liquid fluctuations were also obat low gas flowrate of 20 MMSCFD but no liquid v

in excess of HP Separator capability was predicted.

Late Life. Theliquid flowrate was constant at the gas flowrates. Slight liquid fluctuations were obser

the low gas flowrates of 20 MMSCFD and 40 MM

but no liquid volume in excess of HP Separator cap

was predicted.

For the low gas flowrates, liquid fluctuation occur

the large total liquid content in the flowline begins to

flow at the flowline low spots. When the appropriate p

build up behind the liquid occurs, these liquid slugs are

further down the flowline eventually reaching the tseparator. This process is cyclic as the liquid buildup v

in the flowline fluctuates when the liquid slugs e

flowline. This operation would continue as long as su

reservoir pressure exists to move the slugs of liquid.

Liquid slugging during steady-state operation was

occur for the late life, low flowrate case from the

simulator results. Most notable, as shown in Figures 6

for the late life, low flowrate case, are fluctuations i

liquid flowrate, total flowline liquid content, and HP sep

liquid level.

Figure 6 shows liquid flowrate at the flowline outl

section prior to the separator and also the total flowline

content. The graph illustrates the following:

The fluctuations observed for liquid flowrate inthat some degree of slugging is present. If no sl

were present, the plotted line would be leve

reaching steady-state conditions.

Although the liquid flowrate varies between 0 anBPD, the flowline liquid content only between

and 15,000 bbls. The liquid content differential

bbls between the high and low values indicate t

slugging conditions are very slight.


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The operability at the low flowrate is evident in Figure 7

which shows the liquid level in the separator for this case. The

graph illustrates the following:

Although fluctuations in liquid are present, the inletseparator can adequately handle the liquid flow to the

topsides at the normal liquid level setpoint with only

slight oscillations in the separator level

Shut-In / Start-Up Simulation Procedure and Summary.

Simulation Procedure. For early, mid, and late life cases, a

simulation of steady-state operation, followed by a total line

shut-in and subsequent full restart was performed to determine

instantaneous slug volumes during startup scenarios. The

objectives of these analyses were as follows:

Determine increased liquid volume using a ramp-uprate (time period in which gas rate goes from zero to

operating rate with a linear increase in flow rate) per

well typical to a field start-up.

Verify that the predicted slug volume is within theliquid handling capabilities of the host platform topside

facilities. The host platform topsides capability was

assumed to be adequate if the accumulated slug volume

was less than the slug tank capacity.

Determine pressure requirements at the wells at restartconsidering liquid holdup for each time point.

The simulation procedure for each case was as follows :

Run simulation with the four wells until a steady-statecondition is reached.

Shut-in all four wells for 24 hours to allow liquidcontent in the flowline to settle to the lowest points.

Start-up the wells one at a time starting with the furthest

well and working forward up the flowline. Each well isramped to full rate over a six hour period. The start-up

of a next well is three hours after the previous start-up.

Summary of Shut-Down and Startup Results

Early Life. Liquid flowrate to the host platform eventuallyincreases above normal liquid rates due to the displacement

of the liquid volume which gravity flowed to the end of the

flowline during the shut-in period. The transient higher

liquid flow did not result in a problem for the separator.

Mid Life. Similar to early life results. The increased liquidflow slightly increased the HP separator level above

normal but never reached the high-high level.

Late Life. Liquid flowrate to the host platform increases

significantly during the transient period after restart. Thisis due to the displacement of the liquid which settles in the

flowline during the shut-in period. The increased liquid

flow (for this staggered start-up scenario simulated) was in

excess of the HP separator capability and thus required the

use of the slug tank (450 barrels accumulated). This

volume is within the capacity of the slug tank.

Whether or not a slugging problem exists for the cases

described above was determined from examining several

outputs from the OLGA simulation. Most notably, the liquid

flowrate, flowline content, HP separator level fluctuatio

slug tank accumulated liquid volume were reviewed.

graphs are shown in Figures 8 thru 10 for the late life ca

Figure 8 shows the liquid volume flow at the la

section upstream of the separator and the total liquid c

in the flowline. The graph illustrates the following:

The wells flow into the flowline is shutdown at h

The wells remain closed for 24 hours to allow theholdup in the line to settle.

After the wells are restarted at hour 48, the content in the flowline rises to almost 8000 b

additional liquid from the restarted wells is intr

into the flowline. This increase occurs as the ga

are low and the liquid in the line present befo

shutdown is yet to be displaced.

After liquid flow to the host facility recommencehour 60, the instantaneous flow to the inlet separa

increases to a maximum of nearly 5500 BPD whi

above the capacity of the liquid flow from the inl

separator to the downstream liquid processing fac

Figure 9 shows the separator level and portrays the rlevel between the oil phase and water/methanol phase

liquid in the separator. The graph illustrates the followin

The relative volume of water/methanol decreasesliquid first arrives at the platform following the s

This higher flow of oil in the initial return of the

due to the separation of the oil and water phases

liquid holdup of the flowline during the shut-in p

The high volume of water/methanol in the flliquid content results in a high flow of water/me

approximately 6 hours after the re-establishm

liquid flow. The water/methanol and oil in the se

varies until steady-state operation is re-establishe

The level in the separator cannot be maintainednormal liquid level and eventually reaches the

high level which activates flow into the eme

dump (flow to the slug tank).

Figure 10 shows the accumulated volume of liqui

flowed to the slug tank over the transient period.

simulation predicted liquid flow through the emergency

it was vital to determine whether the topside slug tank

adequate size to receive the liquid slug volume predic

this case. The graph illustrates the following:

The 450 bbl accumulation predicted is well belcapacity of the 2400 bbl slug tank. In addition, a

start-up period may greatly reduce the 450 bbl va

The great majority of the liquid volume flowing islug tank is the water / methanol phase. This is the separation of the oil phase from the w

methanol phase for the liquids which were resi

the flowline during the shutdown period. The

liquids into the separator after restart are predom

oil phase and arrive at a manageable flowrate as

rate is still low. The subsequent liquid is predom

water / methanol and flowing at a higher rate due

higher gas rates as the wells reach full flow.


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Flow Increase Simulation Procedure and Result Summary.

Simulation Procedure. The objective of these cases was as

follows :

Determine for early, mid and late field life, the effect onthe topside liquids handling of bringing a well on line

(no flow to full flow) with the other wells on the

flowline already flowing.The increase in gas rate also results in a subsequent

increase in liquid rate as represented by the gas / liquid ratios

listed in Table 1. This scenario required thorough study as it

will be a standard operation with a significant potential for

liquid slugging. For each case, the well to be brought on-line

was MC305-3 as this is the highest flowrate well. Higher gas

flow will cause the higher liquid content to be displaced from

the line at a higher rate than the start-up of the other wells.

Using this well is a conservative case for this scenario. The

effect of the higher gas flowrates on liquid content is

illustrated in Figure 4 which was previously described. The

simulation procedure for each point was as follows :

Run simulation with three wells on-line (MC305-3shutdown) until a steady-state condition is reached.

Start-up well MC305-3 at various ramp-up speeds(instantaneous through up to seven days) to determine

the ramp-up achievable for each case that does not

overwhelm the liquid handling at the host platform.

Summary of Results

- Early Life. The liquid rate to the host platform from theflowline is increased for a short period as the higher gas

velocity displaces the additional liquid content (600

barrels) associated with lower flow. The instantaneous

(immediate increase from no flow to full flow) ramp-up

case caused a small volume (


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Figure 13 shows the accumulated liquid into the slug tank

over time for the instantaneous, 12, 48, and 60 hour ramp-up

periods. The graph illustrates the following:

For the instantaneous cases, predicted accumulatedvolume is greater than the slug tank capacity.

For the 12 hour case, the total predicted accumulatedvolume is just below the capacity of the slug tank.

For the 48 and 60 hour cases, the total predictedaccumulated volume is well less than the capacity of

the slug tank.

For the late life case, longer ramp-up times are required

due to the large liquid holdup present in the line. The specific

ramp-up period identified where the accumulated volume did

not exceed the slug tank volume was 120 hours. Figure 14

shows the accumulated liquid volumes in the slug tank for the

instantaneous, 48, 96, and 120 hour cases. The graph

illustrates the following:

For the instantaneous, 48, and 96 hour cases, predictedaccumulated volume is greater than slug tank capacity.

For the 120 hour case, the total predicted accumulated

volume is below the capacity of the slug tank.

Liquid Flow Increase Simulation Procedure and ResultSummary.

Simulation Procedure. The objective of these cases was as

follows :

Determine if a significantly increased liquid rate resultsin slugging which overwhelms the topside liquid

handling facilities.

These simulations were performed only for the late life flow

conditions as this is the worst case scenario for significant

impact on the topsides liquids handling. For the liquid

volume associated with the late life flow of 75 MMSCFD, thewater production (and associated methanol dosing) of one well

was increased to simulate an instantaneous increase in liquid

rate in the flowline. This would be indicative of water

breakthrough in a single well and illustrates the resultant

impact on the host platform liquid handling facilities. The

simulation procedure for this analysis was as follows.

Run simulation with all four wells operating at the latelife flowrate until a steady-state condition is reached.

Increase the water production ratio at MC348-1 tosimulate a sudden increase in liquid rate in the

flowline. The ratios for MC348-1 were increased

from 8 bbls / MMSCF to 25, 50, and 100 bbls /

MMSCF respectively. The gas flowrate for MC348-1in the late life case is 20 MMSCFD. The methanol

flowrate ratio of 1.5 times the water rate is held

constant.

Summary of Results

25 BBL/MMSCF: This water rate increase resulted in anincreased flow of 850 BPD per day (water/methanol).

Total liquid flow increased to 1290 BPD. The liquid

handling facilities as modeled are capable of handling the

excess liquids for this case with no flow to the slu

The pressure at MC348-1 increases with higher fl

liquid content.

50 BBL/MMSCF: This water rate increase resulteflow increase of 2100 BPD of liquid (water/met

Total liquid flow increased to 2540 BPD. The

liquid exceeded slug tank volume in 2.75 days fol

arrival at host platform. The pressure at Mincreases with higher flowline liquid content.

100 BBL/MMSCF: This water rate increase resultflow increase of 4600 BPD of liquid (water/met

Total liquid flow increased to 5040 BPD. The

liquid exceeded the slug tank volume in 1 day fol

arrival at host platform. The pressure at M

increases significantly with higher flowline liquid co

Figure 15 illustrates the results outlined above.

Conclusions No steady-state operation scenarios were identi

which liquid slug volumes were present in excessHP Separator liquid handling capability. For th

majority of cases investigated there was no liquid sl

predicted.

Non-steady-state scenarios were identified which reincreased liquid flow in excess of topside ca

However, there are cases where slug volumes co

operationally mitigated via procedures in which the

inlet flow rates were reduced by controlling the fl

gas rate (e.g. slower ramp-up of well).

Operation with a reduced slug tank volume (


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Figure 1- Schematic Model of Canyon Express Production System

Figure 2: East Flowline Route Profile used in OLGA Simulations

CANYON EXPRESS DEVELOPMENTEAST FLOWLINE ROUTE PROFILE

TRANSIENT STUDY BASIS

HOST PLATFORM

177-2

305-3

348-2

348-1

-8000

-7000

-6000

-5000

-4000

-3000

-2000

-1000

0

1000

0 20 40 60 80 100 120 140 160 180 200 220 240 260

Distance (1000 ft)

Elevation(ft)

WEST

EAST

CANYON EXPRESS DEVELOPMENT

FLOWLINE SCHEMATIC

TRANSIENT STUDY BASIS

KINGS

PEAK

BP

CAMDEN

HILLS

MARATHON

HOST

PLATFORM

ACONCAGUA

TOTALFINAELF

MC

348-1

MC

348-2

MC

305-3

4 miles

MC

305-1

MC

305-2

MC

217-3

DC

133-2

MC

217-2

DC

177-2

11 miles 32 miles

DUAL 12"PIPELINES

GAS EXPORT


9/15


Table 1: Basis for Transient Simulations

Figure 3- HP Separator Model Used in OLGA 2000

Case Early Mid Late

Water Rate (bbls /mmscf) 0.7 2.5 8.0

Methanol Rate (bbls/bbl

water)1.5 1.5 1.5

Condensate Rate (bbls/mmscf) 2.0 2.0 2.0

Host Arrival Pressure (psig) 2000 1000 500

Host Separator Pressure (psig) 1750 750 486

East Line Wells Flow (mmscfd)

MC348-1 50 31 20

MC348-2 50 50 10

MC305-3 60 55 35

DC177-2 50 14 10

Total 210 150 75

MULTIPHASE INLET HP SEPARATOR

LC60"

HLL 3 ft - 9 in

SLUG TANK

EMERGENCY

DUMP

NORMAL

FLOW

FC

CONSTRAINT

2600 to 2800 BPD

CANYON EXPRESS DEVELOPMENT

TRANSIENT STUDY HP SEPARATOR BASIS

TO

INLET

CHOKE

LC

NLL 2 ft - 6 in

CANYON

EXPRESS

FLOW

HLL 3 ft - 9 in

NLL 2 ft - 6 in


10/15


Figure 4 - Flowline Liquid Content at Various Gas Flowrates

Figure 5 - Pressure at End of Flowline at Various Gas Flowrates

Liquid Content East Flowline

Early = 2000 psia, 0.7 H2O, Mid = 1000 psia, 2.5 H2O, Late = 500 psia, 8 H2O

0

5000

10000

15000

20000

25000

0 50 100 150 200 250

Gas Flowrate (mmscf/d)

Liquidcontent(bbls)

Early life

Mid life

Late life

Subsea Inlet Pressure East Flowline

Early = 2000 psia, 0.7 H2O, Mid = 1000 psia, 2.5 H2O, Late = 500 psia, 8 H2O

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0 50 100 150 200 250

Gas Flowr ate (m ms cf/d)

PressureatCamdenHills(psia)

Early life

Mid life

Late life


11/15


Figure 6 - Late LifeSteady-State Operation at 40 MMSCFDLiquid Flowrate at Separator and Flowline Liquid Content

Figure 7 - Late LifeSteady-State Operation at 40 MMSCFDHost Platform HP Separator Liquid Level

LIQUID FLOWRATE

LIQUID CONTENT

0

500

1000

1500

2000

2500

3000

3500

4000

0 12 24 36 48 60 72 84 96 108 120 132 144

Time (Hrs)

LiquidFlowrateatSeparator(BPD

)

13250

13500

13750

14000

14250

14500

14750

15000

15250

FlowlineLiquidContent(Bbls)

Actual Liquid Level

High-High Liquid

Level

2.00

2.25

2.50

2.75

3.00

3.25

3.50

3.75

4.00

0 12 24 36 48 60 72 84 96 108 120 132 144

Time (Hrs)

SeparatorLiquidLevel(ft)


12/15


Figure 8: Late LifeFull Flow / Shutdown / Re-Start (75-0-75 MMSCFD):Liquid Flowrate at Separator and Total Liquid Content

Figure 9: Late LifeFull Flow / Shutdown / Re-Start (75-0-75 MMSCFD):Host Platform HP Separator Liquid Level

LIQUID FLOWRATE

SHUTDOWN

RESTART

LIQUID CONTENT

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

0 12 24 36 48 60 72 84 96 108 120

Time (Hrs)

LiquidFlowrateatSeparator(BP

D)

5500

5750

6000

6250

6500

6750

7000

7250

7500

7750

8000

8250

8500

FlowlineLiquidContent(Bbls)

Actual Liquid Level

High-High Liquid

Level

SHUTDOWN

RESTART

2.00

2.25

2.50

2.75

3.00

3.25

3.50

3.75

4.00

0 12 24 36 48 60 72 84 96 108 120

Time (Hrs)

SeparatorLiquidLevel(Ft)


13/15


Figure 10 - Late LifeFull Flow / Shutdown / Re-Start (75-0-75 MMSCFD)Liquid Accumulation at Slug Tank

Figure 11 - Mid LifeGas Flow Increase (95 MMSCFD to 150 MMSCFD)Flow Rate at HP Separator for Various Ramp-up Times

WATER / METHANOL

OIL

SLUG TANK CAPACITY

RESTART

SHUTDOWN

0

400

800

1200

1600

2000

2400

2800

0 12 24 36 48 60 72 84 96 108 120

Time (Hrs)

AccumulatedVolumeperPhase(Bb

ls)

RESTARTWELL

0

2000

4000

6000

8000

10000

12000

14000

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168

Time (Hrs)

LiquidFlowrateatSeparator(BPD)

INSTANTANEOUS RAMP-UP

12 HOUR RAMP-UP

48 HOUR RAMP-UP

60 HOUR RAMP-UP


14/15


Figure 12 - Mid LifeGas Flow Increase (95 MMSCFD to 150 MMSCFD)Host Platform HP Separator Liquid Level

Figure 13 - Mid LifeGas Flow Increase (95 MMSCFD to 150 MMSCFD)Liquid Accumulation at Slug Tank at Various Ramp-up Times

INSTANTANEOUS

RAMP-UP

Normal Liquid Level

48 HOUR RAMP-UP

60 HOUR RAMP-UP

RESTARTWELL

High-High Liquid Level

2.00

2.25

2.50

2.75

3.00

3.25

3.50

3.75

4.00

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168

Time (Hrs)

SeparatorLiquidLevel(Ft)

60 HR RAMPUP

48 HR RAMPUP

12 HOUR RAMPUP

0 HOUR RAMPUPSLUG TANKCAPACITY

RESTARTWELL

0

600

1200

1800

2400

3000

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168

Time (Hrs)

AccumulatedLiquidVolume(Bbls)


15/15


Figure 14 - Late LifeGas Flow Increase (95 MMSCFD to 150 MMSCFD)Liquid Accumulation at Slug Tank for Various Ramp-up Times

Figure 15 - Late LifeLiquid Flow IncreaseLiquid Accumulation at Slug Tank for Various Liquid Ratios

120 HR RAMPUP

96 HR RAMPUP

48 HR RAMPUP

0 HR RAMPUP

SLUG TANK

CAPACITY

RESTARTWELL

0

800

1600

2400

3200

4000

4800

5600

6400

7200

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168

Time (Hrs)


50 BBL / MMSCF

100 BBL / MMSCF

INCREASELIQUID

SLUG TANK CAPACITY

25 BBL / MMSCF

0

800

1600

2400

3200

4000

4800

5600

6400

7200

0 12 24 36 48 60 72 84 96 108 120

Time (Hrs)


WATER RATIO LIQUID

RATE

25 BBL / MMSCF 2,500 BPD



Documents

19099Canyon Express Slugging and Liquids Handling