workover well control
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Workover Well ControlTRANSCRIPT
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Workover Well Control
• Real differences between drilling and workover
well control.
• In drilling, the uphole shoe is weak zone, while in
workovers, the pay is weak zone.
• Operations in drilling that might break down the
shoe (e.g., shutting in over night with gas
migrating up the annulus), would cause no
problem in workovers in cased holes.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Massive shallow gas release – West Vanguard
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Working Fluids
• Drilling – muds - fluid loss control – allows
operations at high overbalance with
minimum fluid losses.
• Workovers – often clear brines – even small
overbalance causes excessive fluid loss.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Well Control Methods
• Drilling – drillers method
• Workovers – bullheading is common
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Surface Pressure and Equipment
• Allowable surface pressures are higher for
workovers and completions as compared to
drilling operations, at least in relatively new
wells.
• Workovers in older wells may have surface
pressure limitations due to loss of casing
integrity. (Most older wells have lower
formation pressures due to depletion).
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Well Control Considerations
• Well History (mechanical damage, corrosion, abrasion, etc)
• Tubular and wellhead details
• Casing and cementing details
• Annular heating and thermal expansion
• Workover fluid program
• Current mechanical condition
• Directional Survey data
• Expected reservoir and fracture pressures
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Four Well Conditions
• Static Condition – wellbore fluid and tubing are stationary.
• Forward circulating – fluids are pumped down the tubing and up the annulus.
• Reverse circulating – fluids are pumped down the annulus and up the tubing.
• Tripping – tubing is being pulled or run into well.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Static – Hydrostatic Pressure
• Ph = 0.052 * FD * TVD
Ph = hydrostatic pressure, psi
FD = fluid density, ppg
TVD = true vertical depth, ft
0.052 = 7.49 (gal/ft3) / 144 (in2/ft2)
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Static – Hydrostatic Pressure
• Calculate the hydrostatic pressure exerted in a vertical well on the perforations at 5000 ft in a well filled with 10 ppg workover brine.
Ph = 0.052*10*5000 = 2600 psi
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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The Extreme Case – Horizontal
Well • MD or TVD?
Difference in volumes and in pressures
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Bottom Hole Pressure
• BHP = Ph + Ps
– BHP = bottom hole pressure
– Ph = hydrostatic pressure
– Ps = surface pressure
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
Ph
P
s
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Forward Circulating/Friction
Pressures
• Pump Pressure =
Friction pressure in flow line +
Friction pressure in tubing string +
Friction pressure in downhole tools +
Annular friction pressure +
Annular hydrostatic pressure -
Tubing hydrostatic pressure
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
Annula
r F
rict
ion
Tool Fric
Tubin
g F
riction
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Forward Circulation
• Circulation Path
• Friction pressures make BHP during circulation higher than at static conditions.
• Annular backpressure is additive to annular friction pressure for BHP
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
Annular
friction
Tube
Fric
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BHP with a Choke
• During regular circulation,
with 10 ppg brine, there is
200 psi annular friction and
300 psi backpressure is held
with a choke.
• Calculate the BHP.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
BHP?
300
200
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BHP with a Choke
• BHP = Ph + Ps + Pfann
Note that this is the back pressure side of the
equation
• BHP = 0.052*(10)(5000)+300+200
• BHP = 3100 psi
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Equivalent Circulating Density
• ECD = Pfann /(0.052 * TVD) + FD
ECD = equivalent circulating density, ppg
Pfann = annular friction (psi)
TVD = true vertical depth (ft)
FD = fluid density, ppg
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Equivalent Circulating Density
• Calculate ECD for circulation with 10
ppg brine and 200 psi annular friction
pressure.
• ECD = 200 / (0.052*5000) + 10
• ECD = 10.77 ppg
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Reverse Circulating
• BHP = Ph + Ps + Pftbg
BHP = bottom hole pressure, psi
Ph = hydrostatic pressure
Ps = surface pressure
Pftbg = tubular friction (psi)
The bottom hole pressure is highly influenced by the tubing friction – annular friction is not felt except as a loss of surface pressure or hydrostatic – only important in close annular clearances.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Reverse Circulating
• Calculate the BHP at 5000 ft while
reverse circulating with 10 ppg brine
and holding 300 psi back pressure on
the tubing choke. Friction in the
tubing is 500 psi. Friction in the
annulus is 0.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Reverse Circulating
• BHP = Ph + Ps + Pftbg
• BHP = 0.052(10)(5000) + 300 + 500
• BHP = 3400 psi
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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ECD Reverse Circulating
• ECD = Pftbg/(0.052* TVD) +FD
Pftbg = friction pressure in the tubing, psi
TVD = true vertical depth, ft
FD = fluid density, ppg
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Swabbing
Swab occurs in upward
tool/tube movement.
Any large BHA can swab.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
BHPs<BHPi
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Red Flags for Swabs
1. Fast Pipe Movement
2. Viscous Fluids and High Gel Strengths
3. Tool OD > 80% Pipe ID
1. Packers
2. Liners
3. Perf guns
4. Scrapers
5. Pumps
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Possible Indicators of a Kick
1. Cutting of fluid
2. Change in chloride content of water
3. Incorrect fill-ups
4. Decrease in pump press while circulating – decrease in hydrostatic pressure from kick.
5. Increase in flow line temperature
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Handling a Workover Kick
• Minimize the influx
– Early recognition and quick shut in
– Estimate of type of kick from pressure
difference
– Problems with hole geometry
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Trapped Pressures and Fluids
• Completions well work may encounter trapped fluids or pressures
• Trap areas:
– Plugs, packers, SSSV, surface valves – need equalization path
– Tools – below large tools with viscous fluids in wellbore
– Debris plugs – fill, paraffin, scale, corrosion
– Well Design – large annuli (minimize), dual strings, cross-overs, deviation, washouts, cross-flows
– Annular thermal expansion Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Special Cases of Control
• Trapped Gas
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
Gas in the annulus above the end of
tubing, is stored energy. High stored
energy after fracturing or bullheading
will pressure up after shut down. It
may bleed off rapidly by displacing
fluid into the formation.
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Mechanical Failures
• Equipment malfunction or failure is
involved in 20% of blowouts.
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Effect of Casing Size
• 10 ppg fluid, 20 bbl gas kick, 2-7/8” tubing
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Effect of Kick Type and Density
• 10 ppg fluid,
20 bbl kick,
7” Casing,
2-7/8” tbg
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As Gas Migrates Upward…..
• Gas migration is the upward movement of a gas
bubble – occurs without circulation – fluid
density difference is the driver.
• Calculate the increase in BH pressure and
surface pressure when a gas kick migrates 500 ft
in a 5000’ deep well filled with 10 lb/gal brine.
Initial SICP is 400 psi and initial reservoir
pressure is 3000 psi.
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Gas Migration Problem
BHP = bubble press + hydrostatic below bubble
BHP = 3000 + (0.052)*(10)*(5000’-4500’)
BHP = 3260 psi
4500 ft
5000’
3000 psi
400 psi
3260 psi
660 psi
Ps = bubble press +
Phyd to bubble = 3000-
(0.052(10)(4500) = 660
psi
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Gas Expansion
• Expansion – simple approach – Boyle’s Law
• P1V1 = P2V2
Calculate the volume of gas downstream of the
choke when a 1 bbl kick at 3000 psig (3014.7
psia) is bled off.
V2 = P1V1/P2 = (3014.7 psi)(1 bbl) / (14.7 psi)
V2 = 205 bbl of gas (standard conditions) vented.
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Gas Expansion
• One barrel of gas, vented to atmospheric pressure,
expands to:
– From 500 psi => 35 bbl
– From 1000 psi => 69 bbl
– From 1500 psi => 103 bbl
– From 2000 psi => 137 bbl
– From 3000 psi => 205 bbl
– From 5000 psi => 341 bbl
Large kick volumes under high pressures will take very long
time to vent!
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Calculation – 10 bbl gas kick
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
• 10 bbl gas kick in casing, perforations at
5000 ft. 7”, 23 lb/ft casing, 2-7/8” tubing, 9
ppg brine. SITP = 260 psi. Gas gradient =
0.1 psi/ft, Calc BHP and SICP. Annulus
capacity = 0.0313 bbls/ft.
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Calculation – 10 bbl gas kick
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
• BHP = Phyd + Ps = 0.052(9)(5000) + 260 = 2600 psi
• Need height of gas kick in casing
• Kick height = 10 bbls/0.0313 bbls/ft =319.5’
• Mud height = 5000 – 319.5 = 4680.5 ft
• Phyd = (319.5 ft)(0.1 psi/ft)
+(0.0052)(9)(4680.5) = 2222 psi
• SICP = BHP - Phyd = 2600 – 2222 = 378 psi
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Abnormal Pressures
• Reservoir pressure above normal (0.465 psi/ft or 9
lb/gal).
• Sources
– Known high pressure pays
– EOR projects (floods, gas inj, WAG, CO2, steam, etc)
– Disposal zones
– Tool and thread leaks
– Cross-flowed zones
– Recharged zones
– Annular heating (thermal expansion) during start-up
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Production – Temp rises 45oF / 7oC to 115oF / 46oC
Gas lift supply – 2000 psi
Trapped Annular Fluid
82 ft or methane gas
2118 ft of diesel
2200 ft
13-3/8”, 72 lb/ft, L-80, Burst rating is 5370 psi
9-5/8”, 47 lb/ft, N-80, Collapse rating is 4700 psi.
Problems – Will annular pressure rise to a level that
could collapse the 9-5/8” or burst the 13-3/8”?
What prevention methods are available?
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Data:
Temp rises from 45oF / 7oC to 115oF / 46oC
Diesel expands w/ temp rise: 0.0004 /oF or 0.00072 /oC.
Gas expands with temp rise and is compressed by liquid
expansion – also opposes liquid expansion – result?
Pressure rises quickly – liquid is dominant effect.
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82 ft
2000 psi
2000 psi
3000 psi
25 ft
45oF or 7oC 75oF or 24oC
>5000 psi <3 ft
100oF or 38oC
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Shut-In Procedures –
circulating/drilling/cleanout 1. Alert crew
2. Position work string w/ tool joint clear of BOP and
accessible from rig floor
3. Stop pumps
4. Close uppermost applicable preventer – confirm shut in.
5. Read and record:
1. SITP (bump float if one is in use)
2. SICP
3. Pit gain, bbl
4. Time
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Shut-In Procedures – while
tripping 1. Alert crew
2. Stab fully open safety valve
3. Close safety valve
4. Position work string w/ tool joint clear of BOP and accessible from rig floor
5. Stop pumps
6. Close uppermost applicable preventer – confirm shut in.
7. Read and record:
1. SICP
2. Pit gain, bbl
3. Time
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text
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Shut-In Procedures – wireline
1. Alert crew
2. Increase pressure to grease injector
3. Attempt to pull wireline tool into lubricator without additional flow. Close in if necessary – avoid moving wire through ram blocks.
4. Close uppermost applicable tree valve (or wireline blind ram if wire is in the hole) confirm shut in. Cut wire as a last resort.
5. Read and record:
1. Shut in surface pressure
2. Estimate loss of fluid from lubricator, if any.
3. Time
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Special Cases – special
procedures needed • Pipe out of hole
• Fishing operations
• Pulling/running rods
• Wells on gas lift
• Pulling/running submersible pumps
• Wells with ScSSV’s
• Daylight only operations
• Interchanging production tree and BOP stack
• Coiled tubing
Workover Well Control and Blow Out Prevention Guide – BP-Chevron Alliance Text