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D I S T I N G U I S H E D A U T H O R S E R I E S

84 APRIL 1999

APPLICATION OF TRANSIENT-MULTIPHASE-FLOW TECHNOLOGYDale D. Erickson, SPE, and Michael C. Mai, SPE, Multiphase Solutions Inc.

INTRODUCTION

The challenges associated with multiphase flow are as old as the oil

business itself. The natural flow from most wells consists of some

mixture of oil, gas, and water. Historically, separators were placedas close to the wellhead as possible to avoid problems associated

with multiphase-flow behavior. However, as production has moved

into more hostile environments and project and operating philoso-

phies have changed, use of multiphase transport in oil and gas pro-duction operations has increased. For example, in the production

scenario in Fig. 1, all production (gas, condensate, and water) from

the subsea wells and the wellhead platforms is transported com-mingled to the central platform. At the central platform, liquid/gas

separation is performed so that the gas can be compressed and theliquid pumped. The fluids (liquid and compressed gas) are thenremixed and transported as a multiphase mixture in a single

pipeline to shore. Onshore, the fluids are separated to sales specifi-

cation. In this scheme, methanol may be needed at the wellhead to

prevent formation of hydrates. The methanol is removed from the

water phase onshore and sent back offshore for reuse. If methanolis not required in the infield network, the water can be separated

on the central platform and disposed of offshore.

To make production scenarios like this one both feasible and reli-

able, transient-multiphase-flow modeling is used in many differentways. This paper provides brief descriptions of these techniques

that are based on our experience with more than 200 individual

studies of multiphase pipelines and related facilities worldwide.

These applications include conventional offshore, deepwater, arc-

tic, and desert production and transportation systems.

LINE SIZING

Selecting the line size for a single-phase pipeline is relatively direct.

The greatest anticipated flow rate should be established, the avail-

able pressure driving force should be determined, and pressure-

drop relationships should be used to select a line size large enoughto transport the required flow. Typically, economics may drive the

line size to still greater values to accommodate future production

or third-party fluids.

The line-sizing problem in multiphase flow is more problematicbecause bigger is not necessarily better. Fig. 2, which shows theenvelope of operability, explains this concept. The envelope has

three main curves. The snake-like curve shows how production is

expected to change with water cut (as the field matures and addi-

tional wells are brought on line). These production numbers reflect

total liquid flow rates. The upper curve establishes the throughput

limit of the pipeline on the basis of pressure-drop constraints, as

governed by expected flowing wellhead pressures. The region below

the lower curve establishes the production and water-cut combina-tions where terrain slugging occurs. The region between the curves

is the envelope of operability. In this case, production over most of

the field life is inside the envelope. Increasing the line size moves the

envelope up, and decreasing the line size moves it down. In this way,

operational impacts of different line sizes can be assessed.The key to making the envelope of operability a reliable design

tool is to use an accurate dynamic model to calculate the bound-

aries. In preliminary engineering, a design engineer often usessteady-state simulators (or other correlations based on low-pres-

sure, small-diameter, air/water laboratory data). These relation-ships should be used with caution. In one case that we encountered

while working on a subsea pipeline, transient-model predictions

for the pipeline pressure drops were 30% greater than the steady-

state-model predictions (with similar differences in predicted liq-uid holdups). On the basis of the transient-model results, the line

size was reduced by 2 in. from the size initially recommended on

the basis of steady-state-model results. Field data subsequently

confirmed that the transient-model predictions were within 8% of

the actual values. If the larger line size had been installed, thepipeline would have been in the terrain-slugging region under nor-

mal flowing conditions, creating substantial operational problems.

LINE PACK/UNPACK

Gas is difficult to store in large quantities unless converted to liq-

uefied products. Therefore, offshore gas production typically is reg-

ulated to match onshore demand. Because of the storage (com-pressibility) and resistive properties (friction loss) of the pipeline, a

time lag occurs between changes in the gas flow rate into the

pipeline and corresponding changes in the gas flow rate out of the

pipeline. To maintain deliveries during short offshore shutdowns,

the pipeline may be operated in a packed condition. Packed inthis sense refers to the additional gas that can be stored in the

pipeline by increasing operating pressures. These operating pres-

sures are higher than the driving force required simply to transport

the gas to shore given the minimum allowable arrival pressure.Moreover, an oversized line has been used in some cases to providethe line packing necessary to ensure uninterrupted onshore deliv-

ery during temporary offshore shutdowns. In multiphase systems,

this issue becomes more complicated because the liquid reduces

the volume available for gas compression. Furthermore, increasesin flow rate can produce the intended gas volumes but may also

yield problematic quantities of liquid.

Beyond design considerations, commercial and operations peo-

ple need to know the delivery capacity of the system throughout the

day. On-line models have been developed to provide an accurateassessment of potential performance. For example, an operator

knows that the compressor offshore will be down for 4 hours in the

afternoon for planned maintenance activities. The on-line modeltakes the current state of the pipeline (continuously calculated from

Copyright 1999 Society of Petroleum Engineers

This is paper SPE 52757. Distinguished Author Series articles are general, descriptive repre-sentations that summarize the state of the art in an area of technology by describing recentdevelopments for readers who are not specialists in the topics discussed. Written by individu-als recognized as experts in the area, these articles provide key references to more definitivework and present specific details only to illustrate the technology. Purpose:to inform the gen-

eral readership of recent advances in various areas of petroleum engineering. A softboundanthology, SPE Distinguished Author Series: Dec. 1981Dec. 1983, is available from SPEsCustomer Service Dept.

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APRIL 1999 85

production data) and the current gas-nomination profile and fore-

casts the size of the shortfall (or surplus) that may be expected in

the contract period. In addition, if the operator wants to sell gas onthe spot market, the on-line model can forecast the volume of sur-

plus gas currently available as line pack (and any ramp-up limita-tions governed by liquid holdup in the line). Similarly, if production

is increased offshore, the amount of gas that can be made available

at the sales point can be forecast as a function of time.

SAFETY-SYSTEM ANALYSIS

There are several applications for transient-multiphase-flow tech-

nology in the area of safety-system analysis. These include high-

integrity pressure-shutdown systems, pressure-relief systems, lineruptures, surge analysis, and leak detection. Again, the presence of

two phases substantially affects the flow transients and the dynam-

ics of pressure buildup or bleed-down. The following example

illustrates a typical type of analysis.

A live (volatile) -condensate pipeline was simulated to determineacceptable closure times for a shutdown valve, which protects a

pipeline in case of line breaks. Simulations showed that, without a

fast-closing shutdown valve in place, more than half the pipeline

inventory would leave the pipeline. Gas is formed as the pressure inthe pipeline falls, thereby pushing additional liquid out of the

pipeline. This type of failure is the worst case of all the fire scenar-

ios because condensate density is much higher than gas density.

Consequently, fast-closing valves were required. Multiphase-flow

simulations then were used to determine whether the valve seatscould handle the surge stress imposed by the rapid valve closure.

SLUG-CATCHER SIZING

One problem with multiphase flow is that increasing the distance

between the separator and the multiphase-flow source increases thelikelihood that liquid will arrive at a variable rate. For this reason,large separators, called slug catchers, are located at the end of

multiphase flowlines. The required slug-catcher size depends on the

liquid-handling or drawdown rate, frequency with which the

pipeline is to be pigged, and range of swing in anticipated flow rates.

In gas/condensate pipelines, the primary cause of slug-catcherflooding is ramp-up slugs. Ramp-up slugs are not true slugs but

waves of liquid caused by the increase in gas flow rate (which

sweeps liquid out of the pipeline). These ramp-up liquid slugs are

a problem because of their potential to fill (flood) the slug catcher,

causing a costly system shutdown. Ramp-up slugs are particularlyharmful because they occur when the flow rate is increasing and

the gas is in high demand. The following procedure is used to sizea slug catcher for this type of service.

First, steady-state simulations are run at a number of flow rates.

Next, the flow rate is ramped up from these initial states and theliquid flow rate leaving the pipeline recorded. This information is

sent to a slug-catcher model, which calculates the maximum

required slug-catcher size for a range of assumed liquid-handlingrates. Fig. 3 shows this information for several cases. Once theslug-catcher/liquid-handling rate is selected, a curve can be gener-

ated that shows how high the flow rate can be ramped up for a

given initial steady-state flow rate. Because many systems achieve

steady-state infrequently, on-line models have been developed2 to

predict accurately how fast the flow rate can be increased given the

current pipeline condition (on the basis of historical field data).

The on-line model then controls the flow rate by controlling thechoke position of each well in the field.

Sizing a slug catcher for a pipeline that is pigged regularly is rel-

atively straightforward. First, a graph (Fig. 4) is generated with

information from approximately 50 transient-multiphase-flow sim-

ulations. Fig. 4 shows slug sizes for various pigging intervals asfunctions of flow rate. A cost/benefit analysis is then performed to

balance pigging frequency with slug-catcher size. The transient

pigging analyses used in design work usually are based on steady-

state starting conditions (liquid holdups). On-line models can be

used in field operations to predict pigging requirements accuratelyon the basis of a current assessment of the state of the pipeline

(which may be far from steady state).

In oil systems, terrain and hydrodynamic slugs dominate liquid

arrival rates and are the design basis for slug-catcher sizing. Terrain

Fig. 1Wet-gas gathering and transmission. Fig. 2Envelope of operability.

Fig. 3Ramp-up slugging behavior in a 14-in. North Sea flow-line at 265 psia.

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slugs typically can be controlled by means of gas lift, control valves

at the top of the riser, or line-size selection. Fig. 2 shows that the

envelope of operability expands when gas lift is used. Field obser-

vations have shown that the multiphase-flow simulations of these

strategies accurately predict this behavior. For example, slug-con-trol valves work best when they control pipeline backpressure and

a large reset time constant is used to dampen the dynamics of thecontrol moves.

For hydrodynamic slugging, a model capable of tracking indi-vidual slugs is used. The output from the slug-tracking model is fed

into the slug-catcher model to determine whether the slug catcher

floods. An additional twist with hydrodynamic slugs is that slug

sizes are not uniform but follow a frequency distribution. Slug size

also is affected by fluctuations in boundary conditions. Therefore,under these conditions, slug-catcher sizing requires some proba-

bilistic information, such as typical variance in slug-catcher pres-

sure and the design-slug basis. The design-slug basis is defined as

the maximum slug size the system must handle (e.g., the 1 in 1,000

slug or the 1 in 1,000,000 slug). Slug-catcher size is selected so that

its cost is balanced with the cost of a slug-induced shutdown.

CORROSION-INHIBITOR TRANSPORT

Most operators prefer to use carbon-steel pipelines because of thelower material cost compared with pipes made of special alloys. In

multiphase service, however, the danger of internal corrosion

always exists. Corrosion inhibitors typically are added at levelsbetween 10 and 1,000 ppm. For a corrosion inhibitor to function

properly, it must cover the entire surface of the pipeline at the cor-rect concentration. Multiphase-flow simulation aids the corrosion

engineer by estimating the concentration of the inhibitor at various

locations along the pipeline length.3 One problem is that corrosion

inhibitor is carried in the bulk phase. At some locations, conden-

sation occurs that dilutes the inhibitor concentration. Under cer-tain flow conditions, liquid flow is stagnant in some locations and

solids (sand) can deposit. The corrosion potential is higher in these

locations. Multiphase modeling can determine whether the solids

can be re-entrained or whether the pipeline should be pigged to

facilitate solids removal.

HYDRATE/PARAFFIN CONTROL

At low temperatures, hydrate and paraffin formation is possible.

Both of these solids have the potential to plug a flowline. Typically,

any subsea well or flowline at shut-in conditions may be in the

hydrate-formation region.4

Pipelines often are buried and/or insulated to lower heat lossesand keep temperatures elevated. However, this does not cure start-

up and shutdown problems. To study these problems, a transient,

soil-heat-conduction model was developed.5 For a subsea pipeline,

the model showed that the pipeline cools down to hydrate-forma-

tion temperature in approximately 24 hours (previous simplifiedmodels predicted cooldown times of 4 hours). To prevent hydrate

formation after this period, the pipeline is depressurized; however,if the depressurization is too rapid, the temperature drops because

of Joule-Thompson cooling. Therefore, the depressurization

process is modeled to examine minimum fluid and well tempera-tures along the length of the pipeline.

Long lag times also are seen for warmups. It may take days or

weeks to raise temperatures to steady-state values in buried

pipelines. The problem from a hydrate perspective is that the pres-

sure builds up in a matter of minutes. High pressures and low tem-peratures increase hydrate-formation potential. In some cases,

operating procedures can be developed to keep the fluids out of

the hydrate region. In other cases, methanol injection is required

during startup.

Heated bundles also may be used to provide protection.6 Bundlesoften are considered when it is impossible to maintain the steadytemperatureabove the hydrate- or wax- formation temperature and

chemical inhibitors are not cost-effective. Bundles are simply large

heat exchangers. However, they are much more difficult to design

than standard heat exchangers because of the significant external

heat losses. If the flow rate for the heating medium is chosen incor-rectly and the flow is countercurrent, the temperature in the bun-

dle reaches a minimum. This minimum can be close to the ambi-

ent temperature even when temperatures at the inlet and outlet of

the pipeline remain high. With an incorrect design, hydrates can

then form at the middle of the pipeline, the least desirable locationbecause of the difficulty in removing the plug. To improve perfor-

mance, the return line may be insulated; however, performancedrops if too much insulation is used.

Fig. 4Pigging intervals with line pack.

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PIPELINE STRESS

In multiphase flowlines, the volume andmass rate of liquid in a given pipeline sec-

tion changes with time. As a result, the

dynamic load on the pipeline changes. If a

multiphase pipeline is not anchored down,it can move. Normally, the structural engi-

neer designs the riser and piping supports

using the sum of the individual phase den-

sities multiplied by the effective phase

velocities. In the past, when informationwas not available, loads would be calculat-

ed with the liquid density multiplied by the

maximum gas velocity. For most pipelines

(especially gas/condensate pipelines), this

practice yielded predicted stresses that weretwo to five times too high. Consequently,

more piping support was added than was

required. Conversely, if phase densities and

velocities are used and slugging events arenot accounted for accurately, insufficient

support and excessive vibration, or even

failure, can occur.

SYSTEM MONITORING AND

OPTIMIZATION

Multiphase flow technology is now beingapplied to system monitoring and opti-

mization.2,7 On-line modeling provides

information about pressures, temperatures,

densities, liquid holdup (volume fraction),

and mass rates throughout the pipeline.With these data, continuous forecasting

provides the operator with information

about allowable ramp-up rates (slugging

dangers), pigging requirements, gas-com-

position tracking, and paraffin-/hydrate-formation potential. Moreover, control

algorithms can be used to regulate individ-

ual well flows, riser control volumes, and

compressor speed. Properly designed con-trol algorithms can prevent well sandout or

liquid loadup, excessive erosion in valves

and manifold piping, and problematic liq-

uid slugging in gathering flowlines and

pipelines. These same techniques can beused to optimize blending and gas-com-

pression requirements and to evaluate gas

deliverability on the day while considering

system performance and planned or

unplanned shutdowns.

CONCLUSIONS

During the last 10 years, explosive growth

has occurred in the application of multi-

phase-flow technology for design, operation,

and optimization of offshoreproduction sys-tems. Increasing utilization of the technolo-

gy has allowed operators to save capital costs

and reduce life-cycle operating and overhead

costs. Moreover, recent use of this technolo-

gy in on-line monitoring and control sys-tems is allowing operators to push existing

systems further, thereby achieving addition-al profits and/or cost savings.

REFERENCES

1. Erickson, D. and Danielson, T.: A

Comparison of ConOlga with Field Data from

a Gas Condensate Pipeline, Proc., Eighth Intl.

Conference Multiphase Flow, Cannes, France

(1997) 19.

2. Erickson, D. and Twaite, D.: A Pipeline

Integrity Monitoring System for Leak

Detection, Control, and Optimization for Wet-

Gas Pipelines, paper SPE 36607 presented at

the 1996 SPE Annual Technical Conference

and Exhibition, Denver, Colorado, 69

October.

3. Erickson, D., Buck, E., and Kolts, J.:

Corrosion Inhibitor Transport in Wet-Gas

Pipelines, J. Materials Performance

(September 1993) 32, 49.

4. Erickson, D. and Brown, T.: Occurrence of

Hydrates in Multiphase Flowlines, Proc.,

New York Academy of Sciences Intl.

Conference on Natural Gas Hydrates, New

York City (April 1994) 715, 40.

5. Erickson, D. and Mai, M.: A Transient

Multiphase Temperature-Prediction Program,

paper SPE 24790 presented at the 1992 SPE

Annual Technical Conference and Exhibition,

Washington, DC, 47 October.

6. Brown, T. et al.: Application of a Transient-

Heat-Transfer Model for Bundled Multiphase

Pipelines, paper SPE 36610 presented at the

1996 SPE Annual Technical Conference and

Exhibition, Denver, Colorado, 69 October.

7. Lamey, M.F. and Wasden, F.: Dynamic

Simulation Model Aids Mensa Development,

Oil & Gas J. (10 August 1998) 96, 72.

SI METRICCONVERSION FACTORS

bbl1.589 873 E01=m3

ft32.831 685 E02=m3

Dale D. Erickson is a principal consul-

tant with Multiphase Solutions Inc. in

Houston, where he has developed real-

time, transient-multiphase flow simula-

tors and control/optimization software

for multiphase pipelines. He has con-

ducted technical studies on transient

multiphase flow worldwide. Erickson

holds BS and MS degrees from theColorado School of Mines and a PhD

degree from Rice U., all in chemical

engineering. Michael C. Maiis a princi-

pal consultant with Multiphase Solutions

Inc. in Houston where he has developed

on-line, forecasting, and optimization

software for pipelines and related

process equipment. He has conducted

technical studies worldwide on transient

multiphase flow in oil and gas systems.

Mai holds a BS degree from the U. of

Notre Dame and MS and PhD degrees

from the U. of Texas at Austin, all inchemical engineering.

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