workover well control

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

Massive shallow gas release – West Vanguard

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.


Well Control Methods

• Drilling – drillers method

• Workovers – bullheading is common


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).


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


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.


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)


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


The Extreme Case – Horizontal

Well • MD or TVD?

Difference in volumes and in pressures


Bottom Hole Pressure

• BHP = Ph + Ps

– BHP = bottom hole pressure

– Ph = hydrostatic pressure

– Ps = surface pressure


Ph

P

s

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


Annula

r F

rict

ion

Tool Fric

Tubin

g F

riction

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


Annular

friction

Tube

Fric

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.


BHP?

300

200

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


Equivalent Circulating Density

• ECD = Pfann /(0.052 * TVD) + FD

ECD = equivalent circulating density, ppg

Pfann = annular friction (psi)

TVD = true vertical depth (ft)



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


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.


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.


Reverse Circulating

• BHP = Ph + Ps + Pftbg

• BHP = 0.052(10)(5000) + 300 + 500

• BHP = 3400 psi


ECD Reverse Circulating

• ECD = Pftbg/(0.052* TVD) +FD

Pftbg = friction pressure in the tubing, psi

TVD = true vertical depth, ft



Swabbing

Swab occurs in upward

tool/tube movement.

Any large BHA can swab.


BHPs<BHPi

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


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


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


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

Special Cases of Control

• Trapped Gas


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.

Mechanical Failures

• Equipment malfunction or failure is

involved in 20% of blowouts.


Effect of Casing Size

• 10 ppg fluid, 20 bbl gas kick, 2-7/8” tubing


Effect of Kick Type and Density

• 10 ppg fluid,

20 bbl kick,

7” Casing,

2-7/8” tbg


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.


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

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.


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!


Calculation – 10 bbl gas kick


• 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.

Calculation – 10 bbl gas kick


• 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

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


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?

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.

82 ft

2000 psi

2000 psi

3000 psi

25 ft

45oF or 7oC 75oF or 24oC

>5000 psi <3 ft

100oF or 38oC

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


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


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


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

Documents

hydrostatic pressure

surface pressure workover

hydrostatic pressure

control considerations

control methods

hole pressure ph

psi workover

common workover