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
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. Restriction
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
Beans are fixed (non adjustable) orifices ID size is in 64 ths 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, P 1 Pressure drop through the orifice Pressure recovery, P 2
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/P 1 ) 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 Imploding bubbles and shock waves The rapid collapse of the bubbles causes high velocity movement of liquid and damage around the site. Pressure recovery line limit of damage
VENA Contracta Phenomenon P r e s s u r e P 1 Delta P Recovery P 2 Distance Flow Traveled 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 Press 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. P 1 T 1 dp Temperature Distance Traveled T 2 P 2 Freezing Pt Recovery Recovery Temperature drop across a choke is about 1 o F 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 60 o F. Used as the flow capacity index Does not correspond to a specific throttling method.
Choke Calculation Example Note: for accuracy the upstream press must be twice downstream press. 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
Flow rate estimation by the pressure and choke size for dry gas. Q est. = 24 * (P 1 +15) * Choke size 2 /1000 For a tubing pressure of 4000 psi and a 24/64 choke, the gas flow estimate is: Q est. = (24 * (4000+15) * (0.375) 2 ) / 1000 Q est. = 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.