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Foam...The new liquid accumulation

reducer in gas pipelines

Thereza Karam

December 2012

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Agenda

• Major problems in multiphase gas pipelines

• Use of foaming agents to prevent and remove

liquid accumulations in gas pipelines

• Types of foaming agents

• Foam Flow Processes definition and

description

• Effect of foaming flow on pressure drop

• Advantages and disadvantages of foam

usage

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Problems in Multiphase Gas Pipelines

• Gas Hydrate due to cooling of the pipe

• Corrosion due to the contact of dissolved CO2 in

condensed water within long Carbon steel pipelines

• Inorganic Scale (carbonates and sulphates) due to

fluid mixing

• Liquid Holdup

Typical Fluid Challenges

encountered in multi-phase flow

pipelines

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Liquid Accumulations in Gas Pipelines

Concerns for gas transportation from offshore to onshore

facilities:

• Rugged sea floor Not perfectly horizontal pipeline

• Inclination of pipelines especially for irregular terrains

and multiphase flow

Result: Liquid accumulations in low lying parts of the

pipeline

Modeling of liquid accumulation in inclined pipelines

Hedne 2012

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Overcoming Liquid Accumulations How?

Inducing a foaming flow in the gas pipelines

What is a foam ?

Continuous liquid phase that surrounds and traps the gaseous phase

How to stimulate foaming flow formation in pipes?

By the use of foaming agents

What is a foaming agent?

Additives used for the preparation of foam

It can be either:

1- Blowing Agents

2- Surfactants

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Foaming Agents - Blowing Agents

Definition:

Gas that forms the gaseous part of the foam

Types of gas formation:

1- Gas that forms at the same temperature as

that of the foam formation

2- Gases generated by chemical reactions

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Foaming Agents: Surfactants

Definition:

Chemicals that:

1- adsorbs at an interface, lowering the surface tension or interfacial tension between the fluids

2- increases the colloidal stability of a liquid inhibiting coalescence of the bubbles

Structure:

Molecules with a hydrophilic polar head group (blue) attached to a hydrophobic tail (green) which is usually a fatty hydrocarbon chain

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• Concentration at the

liquid-gas interface in

the foams

• Function:

Can act as foaming

agents or defoamers

Foaming Agents: Surfactants • Self-Orienting:

˗ Hydrophilic group in an aqueous environment

˗ Hydrophobic tail in a non-aqueous environment

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Classified based on the charge of the hydrophilic head into:

1- Non-ionic: the head does not have any charges such as

polyoxyethylenated non-ionic surfactants

2- Anionic: the head is negatively charged such as

carboxylates, sulfates, sulfonates and phosphates

Foaming Agents: Surfactants

3- Cationic: the head is positively

charged such as long chain amines

and quaternary amine salts

4- Amorphoteric: the head has two

oppositely charged groups

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Types of Foaming Agents (Surfactants)

Used

Choice of foaming agent

properties for desirable foam

characteristics

– The one with the longest

half-life

– At the minimal surfactant

concentration

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Foam Composition:

gas bubbles dispersed uniformely throughout a continuous liquid phase

Behavior:

treated as a homogeneous fluid with both variable viscosity and density

Characteristics:

Low density & Extremely high viscosity

Make-up:

Two phases, gas (compressible) and liquid the only compressible non- Newtonian fluid

Properties:

1- a yield stress

2- non-linear shear: near the wall, bubbles will migrate, foaming a lubricating liquid rich layer slip effect between the foam and the wall

Behavior depends on:

1- Bubble size (50 μm to few mm)

2- Texture of the bubble

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Foaming Flow It is dominated by the properties of a thin boundary region which

produces the effect of slip Foam flow ≠ Multiphase flow

What controls the flow of foam in pipes?

The slip layer thickness (10 μm for typical foams)

estimated from the average bubble diameter and the

expansion ratio

Schematic of the velocity field in the case of

viscous foam flow lubricated by a thin layer of

pure fluid

Peysson et al. 2008

Calvert 1990

with 𝛿

𝑑=

2

3 𝐸 − 1 𝐸 =

𝑢𝑓𝑜𝑎𝑚

𝑢𝑙𝑖𝑞𝑢𝑖𝑑

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Foam Flow Process

Foaming/Defoaming

These two processes (Steps 101 and 103) can be

implemented in three different techniques:

1- In-Situ

2- In-Line

3- In an auxiliary side stream

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1-In-Situ

202: Means for generating a foam by Agitation

203: Means for transporting the foam through the transport pipe

204: Means for breaking the foam

205: Optional means for introducing additives to the foam

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2- In-Line

301/308: Gas-dominated inflow/outflow

302/305: Foam generation / defoaming means

303/306: Valve separating the flow from the foam

generation/defoaming means

304/307: Region of foam generation/defoaming

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3- In an Auxiliary Side Stream

401/410: Gas dominated inflow/outflow

402/406: Valve to direct the flow/foamed flow

403/407: To auxiliary side flow

404/408: Foaming/defoaming means

405/409: Valve to control the foamed/defoamed fluid

entrance to pipe

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Transport of Foam in Pipe

Transport pipe can be:

– Completely filled with foam it ensures a homogeneous

plug flow regime along the line

– Partially filled with foam it causes intermittent foam plugs

it sweeps liquid from the pipeline more efficiently than

gas alone

• Less liquid inventory in the pipeline Lower

Pressure drop

Fact Side:

Gas in pipelines has a High Reynolds Number (Re ~107) due to high

density and low viscosity at typical operating pressure (100 bar)

For Low Re, friction factor depends on Re

For High Re, friction factor depends on wall roughness

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The Foam Effect on the Pressure

Drop in Pipes Method 1: Not accounting for slip layer thickness

Blauer et al. 1974

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The Foam Effect on the Pressure

Drop in Pipes Method 2: Accounting for slip layer thickness

Briceño et al. 2003

N.B: The high friction factor resulting for pipes

with foaming flow is due to the very small size of

the lubricating layer

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The Foam Effect on the Pressure

Drop in Pipes

When having a foam flow in gas pipelines, the

viscosity is increased and the density is decreased

Low Re, High friction factor and Higher ΔP

compared to multiphase gas flow

Free body diagram of a flowing medium inside a pipe

Eren 2004

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The Foam Effect on the Pressure

Drop in Pipes

• The Pressure drop increases with the increase in gas flow rate,

foam velocity, quality or foam height in the pipe

Briceño et al. 2003

• Pressure drop can range

between 10 and 40%

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Advantages and Disadvantages of the

Use of Foam in Offshore Pipeline

Advantages Disadvantages

Reduction of surface tension Higher Pressure drop than the multiphase flow

Reduction of flow velocity Reduction in production rate

Change in flow regime Reduced separator efficiency

Prevention of Liquid accumulation in low

lying pipes Loss pump efficiency and capacity

Reduction of slug Fluid carryover in the gas flowlines (small

volumes of foaming agents would reduce this

effect)

Reduction in the size of the Slug Catcher Reduction in the effective volume available for

gas/liquid separation in primary separators (if

not broken down)

Low Cost Foam breakdown due to sudden expansion

Simple and no specific equipment is

needed Difficulty in pressure drop prediction

Small percentage use of foaming agents

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… Is Foam a Good Solution?

• Continuous flow is ensured

• Smaller or no slug catcher facilities onshore are no longer

required

• Low Cost

• Dramatic pressure drop can be reduced

– by the use of smaller foaming agent concentration (or percentage

used)

– By the use of internal coating of pipes

• Reduces the friction and thus the pressure drop

• Increases the mass rate

Foam for flow assurance….a solution for liquid

accumulations in offshore pipelines

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Thank you for your attention

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• Blauer, R., Mitchell, B., & Kohlhaas, C. (1974). Determination of Laminar, Turbulent,

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http://www.glossary.oilfield.slb.com/DisplayImage.cfm?ID=711

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References