Chokes

• Types

• Reasons

• Basics of Operations

• Application

Most Common Chokes

• Positive:

– Fixed orifice

– Disassemble to change bean

• Adjustable

– Provides variable orifice size through external

adjustment

Restriction

Schematic of an

adjustable choke

A choke is a restriction in a

flow line that causes a

pressure drop or reduces the

rate of flow. It commonly

uses a partially blocked

orifice or flow path.

Variable Chokes - good

for bringing wells on

gradually and

optimizing natural gas

lift flow in some cases.

Prone to washouts from

high velocity, particles,

droplets.

Solutions - hardened

chokes (carbide

components), chokes in

series, dual chokes on

the well head.

Beans are fixed (non adjustable) orifices – ID size is in 64ths of an inch.

ID

Choke Uses

• Control Flow – achieve liquid lift

• Maximize use – best use of gas (lift?)

• Protect equipment – abrasion and erosion

• Cleanup – best use of backflow energy

• Control circulation – holds a back pressure

• Control pressures at surface (during flow)

• Control injection – on injection line

Pressure Drop

• Action

– Increased velocity (from gas expansion)

– Vaporization (flashing) of light ends to gas

– Vaporization of water

– Cavitation

– Cooling of gas

– Some heating of liquids

• Detriments

– Flashing – hydrocarbon light ends lost (value lost)

– Cavitation – erosion of surfaces in and around choke

– Erosion– solids, droplets and bubbles in high velocity flow

– Freezing – expansion of gasses cools the area – refrigeration principle

Pressure around the choke

Inlet or well

pressure, P1

Pressure drop through

the orifice

Pressure “recovery” , P2

Problems

• The larger the difference between the inlet

and outlet pressures, the higher the potential

for damage to the internals of the choke.

• When DP ratio (= DP/P1) rises above 0.6,

damage is likely. Look at choke type,

materials of construction, and deployment

methods (multiple chokes needed in series?)

Cavitation During Liquid Flow

Ultra low pressure region in and

immediately below choke causes bubble

to form from vaporizing liquid, Recovery

of pressure causes bubble to collapse; i.e.,

cavitation

The rapid collapse of the bubbles

causes high velocity movement of

liquid and damage around the site.

Pressure recovery line – limit of damage

Imploding

bubbles

and shock

waves

Distance Flow Traveled

Delta P

Recovery

P1

P2

P

r

e

s

s

u

r

e

VENA Contracta Phenomenon

The consequences of the low pressure region in the choke can lead to

severe problems with cavitation and related flashing (vaporization).

Flashing During Liquid Flow

Vaporization of light ends, but no

significant damage in this region since

pressure recovery not above vapor

pressure, hence bubbles don’t collapse.

Pressure recovery occurs downstream,

damage location from high velocity?

Freezing

• Expansion of gas (and solutions containing gas)

cools the surroundings. Excessive temp losses and

presence of water vapor can form an ice plug and

block flow.

Press

Distance Traveled

Recovery Recovery

Freezing Pt Temperature

dP

P1 T1

T2 P2

Temperature drop

across a choke is

about 1oF for

each atmosphere

of pressure drop.

Throttling Methods

• Needle and seat

• Multiple orifice

• Fixed Bean

• Plug and Cage

• External Sleeve

Needle and Seat

• Simplest and least expensive adjustable

• Best for pressure control

• High Capacity

Multiple Orifice

• Quick open and close

• Good rate and pressure control

• An in-line instrument

Fixed Bean

• Best when infrequent change needed

• Used mostly on trees

Plug and Cage

• High capacity

• Good control

External Sleeve

• Superior Erosion Resistance

• Minimizes Body Erosion

Choke Sizing

• Control the flow – maximize production

• Minimized vibration damage

• Minimize erosion damage

• Choke Selection – based on application and

sizing.

Choke Selection (continued)

• Fluid – liquid, gas, or GOR of mix.

• Pressure – both pressure drop and total pressure

• Temperature – range of acceptable temperatures during service

• Solids in flow

• Droplets, bubbles

• Scale and organic deposit potential

Choke Sizing

• Cv = coefficient value

– Number of gallons of water per minute that will

pass through a restriction with a pressure drop

of 1 psi at 60oF.

– Used as the “flow capacity index”

– Does not correspond to a specific throttling

method.

Choke Size

(inches)

Bore Diam

(inches)

Choke Coefficient

MCF/D/PSIA

4/64 0.0625 0.08

6/64 0.0938 0.188

7/64 0.1094 0.261

8/64 0.1250 0.347

9/64 0.1406 0.444

10/64 0.1563 0.553

12/64 0.1865 0.802

16/64 0.2500 1.470

24/64 0.3750 3.400

32/64 0.5000 6.260

Example: a well is flowing through a 10/64 choke at 2175 psig WHP.

What is the dry gas flow rate?

2175 psig = 2190 psia. Choke coeff. for 10/64 = 0.553

Gas rate = 2190 x 0.553 = 1211 mcf/d

Choke

Calculation

Example

Note: for

accuracy – the

upstream press

must be twice

downstream

press.

Flow rate estimation by the pressure

and choke size for dry gas.

Qest. = 24 * (P1+15) * Choke size2/1000

For a tubing pressure of 4000 psi and a 24/64”

choke, the gas flow estimate is:

Qest. = (24 * (4000+15) * (0.375)2 ) / 1000

Qest. = 13 to 14 mmscf/d

Erosion - damage caused by impingement of particles, droplets,

bubbles and even liquid on any solid surface at high velocity.

To reduce erosion, slow down the velocity.

A choke is required for throttling, never

use a gate valve. If wells must be brought

on line without a choke, use the outer wing

valve if rated for the job.

Partly open valve – an erosion area

Erosion in a positive of bean

choke from micron sized

fines and high velocity gas

flow.

Typical flow patterns (and

erosion) in a bean choke.

Erosion at the exit

flange

JPT, March 1998

The velocity profile and pressure drop across a choke with a large

pressure drop – opportunity for erosion is very high.

JPT, March 1998

One solution to the problem is to take the pressure drop in series and

hold a slight backpressure. For example, a 1000 to 0 psi pressure drop

produces a 68 fold expansion in gas volume, while a 1500 to 500 psi

pressure drop produces a 3 fold gas volume expansion.

JPT, March 1998

Quiz – Choke Sizing

• A dry gas well flows at 12 mmscf/d with a

well head pressure of 2200 psi. Select a

choke size and a down stream pressure that

will allow flow but not create damage

through the choke.