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Interventions and Workovers
Well Intervention Core
Intervention
When you intervene in a well, you are usually trying tocorrect a problem or alter the functionality of that well.
When trying to correct a problem, it is very importantthat one first recognize that there is a problem, andsecondly, know what the problem is.
Only after diagnosis and recognition of the problem canone successfully correct the problem.
Intervention
The diagnosis of well problems is covered in
Production Problem Diagnosis Core.
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Learning Objectives
This section will cover the following objectives:
Define interventions and workovers and their general steps
Describe barriers and their use
Determine quality possible solutions to correcting a well problem
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Interventions & Workovers – Define
An all‐inclusive term applying to any form of well re‐entry operation including everything from a simple slick line job to a major workover where the completion string must be pulled
Intervention
A term reserved for major interventions in which, normally, the completion string is pulled
Workover
All workovers are interventions but not all interventions are workovers. In general, workovers are significantly more expensive than simple
interventions.
Interventions/Workovers
Workover
Remove or replace a production packer
Repair tubing leak
Repair casing leak
Replace worn out artificial lift equipment
Clean out wellbore
Recomplete well into another formation
Squeeze off unwanted water or gas zone
Simple Intervention
Shift a sliding side door
Run or pull a wireline‐set tool in the completion
• WR SSSV
• Plug
• Downhole choke
• Pressure recordingdevice
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Three General Steps to a Workover
Diagnosis
Covered in the Production Problem Diagnosis Core skill module
Design
Determine Optimum Workover Solution• Considerations – safety,
cost/economics, likelihood of success, permanence of fix, simplicity, etc.
• Develop detailedprocedure
Execution of Procedure
Select/contract rig, implement procedure, documentation of results
Interventions/Workovers – Diagnosis
Recognition that a Problem Exists (See Production Problem Diagnosis Core module.) Production plots of oil, gas, water,
and ratios versus time Monitor pressures Monitor produced fluids (run
analyses) Visual observations (scale,
corrosion, etc.)
Identify the Cause of the Problem Production Logging Tools (PLT) Field knowledge and experience Offset Wells Structural position
Diagnosis
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Interventions/Workovers – Optimum Solution
List all possible solutions Determine areas of concern
and/or “absolute musts” Barriers, protection of the
reservoir, cost, etc. Qualify possible solutions Rank the possible solutions
and select
Design – Determine the Optimum Solution
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Interventions/Workovers – Barriers
What are barriers?
Capability to hydraulically isolatereservoir from the atmosphere/surface.
Maintain “static” conditions during theoperation.
Options
Hydraulic – Column of kill weight fluid Mechanical – Valves, plugs, etc
Interventions/Workovers – Barriers
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Recommendation
Minimum of two specified for mostoperations (primary + backup)
Prefer minimum of three for mostsituations
May not always be possible to getgreater than two barriers
Company specific – know your companypolicy!
Interventions/Workovers – Barriers
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Interventions/Workovers – Barriers
Surface Barrier ‒ Pressure and Flow Containment
(Sub‐surface Safety Valve) Emergency Subsurface Closure
(Slide Side Door) Hydraulic barrier could be completed by filling tubing with kill fluid via circulating device
Annular isolation
Plug tubing and protect the reservoir
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Qualify Possible Solutions
Items to consider in planning the workover
Obtain a good wellbore schematic.What is the reservoir pressure?
Temperature?
Can the well flow to the surface? Flowing wells are a “yes”, artificial lift wells are usually a “no”.
Are there multiple zones open? Different pressures? Commingled?
Is the formation rock susceptible to damage?
What is the company’s barrier policy and how will you honor it with each
possible solution method?
Does the lower completion need to be removed?
How much rig is necessary to perform the task (i.e., depth rating, HP, pump
capacity, BOP, etc.)?
Can the upper completion be pulled while leaving the lower completion
downhole?
Qualify Possible Solutions
How much annular velocity (AV) is needed when circulating solids out of the well?
What kill methodology to employ?Design the new (post workover) packer fluid.
Can a reduced ID be tolerated? How much? What is the condition of the tubing?
What is the condition of the casing?
What is the existing packer fluid and how compatible is it with the producing formation?
If repairing casing, how much pressure must the repair withstand?
What are the remaining reserves and economics
of the workover?
What density and type of workover fluid is needed?
What type of rig is best suited for the job?
Are the company well supervisor, rig supervisor, and rig personnel properly versed on our company rig procedures and operational safety practices?
What is the expected remaining well life once restored?
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Learning Objectives
This section has covered the following learning objectives:
Define interventions and workovers and their general steps
Describe barriers and their use
Determine quality possible solutions to correcting a well problem
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Wireline Interventions
Well Intervention Core
Learning Objectives
This section will cover the following learning objectives:
Describe the main components of a slickline unit
Describe the main components of a braided wireline unit
Describe the main components of an electric line unit
Compare and contrast the critical operational benefit and/or constraints of each method covered
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Key Element – Rig Selection
SlicklineBraided Wireline
Electric Line
Conventional Workover
(Completion Rigs)
Coil Tubing UnitHydraulic
Workover Unit (Snubbing Unit)
Wireline
Tubing Conveying
Rig Selection
Each rig has advantages and disadvantages
Production Engineer must balance the cost of eachoption with the likelihood of a successful workoverperformed in a safe and efficient manner
Operations must meet the SEE criteria• Workovers must be performed Safely, Efficiently, andEconomically
Keep in Mind
Let’s investigate each rig/unit and learn more about the different methodologies
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Rig Selection – Braided Wireline
Round, single strand ofsteel wire
No electrical conductorRun off of a reel on a
slickline unitShifting sliding sleeves
open or closedRunning a gauge ringSetting or pulling plugs (or other completion
tools)
Dump or bail sand downhole
Fishing inside completion string
Rig Selection – Wireline Options
Slickline
Basic Wireline Options
Braided Wireline
Electric Line
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Rig Selection – Slickline
Simplest system
Least expensive system
Can run under livepressure
Running speed
Round single strand iseasy to seal off with sealrings in stuffing box
Experienced operator can“feel” the tools setting inplace
Sweet or sour serviceavailable
Limited weight pull
No rotation
No circulation
Unable to “push” throughdoglegs or high angle wellbores
No electric current to signal orpower downhole equipment
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Wireline Tool String – Jars
Increases the force delivered – similar to a hammer blow
Assists wireline • in shifting sleeves
• pulling tools or setting tools
• in fishing operations
Also assists in getting tool string unstuck
Purpose
Mechanical Hydraulic Spring
Mechanical or “Spang” Jars
Rope Socket
Stem
Mechanical Jars
Knuckle Joint
Tool String with Jars Closed
Tool String with Jars Open
Rope Socket
Stem
Mechanical Jars
Knuckle Joint
Standard toolstring for wireline with jars stroked open
Jars stroked closed
Stem adds weight and thus increases the hammer force
Do not work in deviated wellbores
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Hydraulic Wireline Jar
Stores force in the wireline as it is pulled and stretched
Hydraulic jars normally allow only for upwards jarring of tool string –mandrel drags through restricted section
Line tension beginningto open jars against oil
resistance
A
Hydraulic Wireline Jar
When mandrel passes the restricted section, the jars “fire” and the stored energy in the wireline is released
B
When fluid by-passarea increases
Piston moves upward RAPIDLY
Line tension beginningto open jars against oil
resistance
A
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Hydraulic Wireline Jar
The mass of the tool string moving upward delivers a sharp impact at the end of the stroke
C
Upward impact
Hydraulic Wireline Jar
Preferred for high inclination and dogleg wells
D
Resetting – stem weightcauses oil to pass
check valve to return to upper cylinder
Top Sub
Piston Seals
PistonRod
Check Valve
BalancePiston
Cylinder
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Wireline Operated Spring Jars – “Accelerator”
(a) (b) (c) (d)
Wireline String – Stem or Sinker Bar
Solid steel barsmanufactured to differentdiameters and lengths
Weight can vary – usually4–12 lbs/ft [6–18 kg/m]
Purpose• Adds weight to the toolstring
• Increases the forcedelivered with jars
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Weight/Stem Requirements for Slickline
Added Weight Necessary to Pull Slickline Downhole under Live Surface Pressure
Surface Wellhead Pressures, psi [bar]
[138] [276] [414] [552] [689]
Added W
eight, lbs[kg]
[45]
[41]
[36]
[32]
[27]
[23]
[18]
[14]
[9]
[5]
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Wireline Surface Equipment – Lubricator and Support
Ginpole *
Wireline Zero.
Otis Type Bowen Type
Line Wiper
Grease Injection Head
Stuffing Box
* Alternate Lifting: Crane Scaffolding/Frame Air Hoist/Derrick Mast
Rope Blocks
Alternate Braided Line Sealing
Hay Pulley
Weight Indicvator
Chain or Steel Strop ONLY
BOP
Lifting Clamp
Quick Unions.
Line angle to be asclose to 90° as
Chain or Steel Strop ONLY
Wireline Clamp
Alternate Braided Line Sealing
BOP
Rope Blocks
Wireline Clamp
Lifting Clamp
Chain or Steel Strop ONLY
Line angle to be as close to 90°
Ginpole*
Hay Pulley
Weight Indicator
Chain or Steel Strop ONLY
Wireline Zero
Stuffing Box
Line Wiper
Grease Injection Head
Quick Unions
Otis Type Bowen Type
* Alternate Lifting:CraneScaffolding/FrameAir Hoist/Derrick Mast
Lubricator
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Common Slickline Operation – Setting a Plug
Packer
SSD
Profile Nipple
Common Slickline Operation – Setting a Plug
Plug Slickline
No Flow –Shut in at Surface
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Common Slickline Operation – Setting a Plug
Profile Nipple
Slickline
Plug Set InsideProfile Nipple
Tubing Plugged Off
Opening a SSD to Pump Kill Fluid
SSD
Shifting Tool Slickline
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Opening a SSD to Pump Kill Fluid
SSD
Kill Fluid
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Rig Selection – Braided Wireline
No electrical conductor
Run off of a reel on a braided line unit
Many onshore rigs have single drums – braided
line only
Offshore units and some onshore units contain both slickline and braided on
double drum units
Multi‐strand spiral woven wire
Jobs that require more strength than slickline
can provide
Wireline fishing operation
Rig Selection – Wireline Options
Basic Wireline Options
Braided Wireline
Electric LineSlickline
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Rig Selection – Braided Wireline
Significantly stronger thanslickline
Second least expensive wireline system
Can run under live pressure
Sweet or sour service available
Limited weight pull (relative to tubing loads)
Slower running speed than slickline
Lack the “feel” of slickline
More difficult to fish
Requires grease injector to complete seal with stuffing box
No rotation
No circulation
Unable to “push” through doglegs or high angle wellbores
No electric current to signal or power downhole equipment
More abrasive than slickline
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Rig Selection – Electric Line
Multi‐stranded woven wire with electrical
conductive cable in the center
Run off of a reel on an electric line unit
Open hole and cased hole logs
Production logging tools
Perforating guns Set production packers
Tractors
Downhole camera
Rig Selection – Wireline Options
Basic Wireline Options
Electric Line
Braided Slickline Wireline
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Stem/Weight Bar Requirements ‒ Braided Electric Line
Added Weight Necessary to Pull Cable into the Well at High Surface Pressures
0 1000 2000 3000 4000 5000 6000 7000 8000 9000 100000
100
200
300
400
500
600
700[318]
[272]
[227]
[181]
[136]
[91]
[45]
Added W
eight, lbs
[kg]
[138] [276] [414] [552] [689]
Surface Wellhead Pressures, psi [bar]
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Rig Selection – Electric Line
Can communicate with toolsdownhole
Can provide power to downhole tools
Can run under live pressure
Significantly stronger thanslickline
Sweet or sour service available
Limited weight pull (relative to tubing)
No rotation
No circulation
Unable to “push” through doglegs or high angle wellbores
Lower running speed than slickline
Lack the “feel” of slickline
Requires grease injector to complete seal with stuffing box
More expensive than slickline andbraided line
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Learning Objectives
This section has covered the following learning objectives:
Describe the main components of a slickline unit
Describe the main components of a braided wireline unit
Describe the main components of an electric line unit
Compare and contrast the critical operational benefit and/orconstraints of each method covered
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Workovers
Well Intervention Core
Learning Objectives
This section will cover the following learning objectives:
Describe the main components of a conventional workover or completion unit
Describe the main components of a snubbing or hydraulic workover unit
Describe the main components of a coiled tubing unit
Compare and contrast the critical operational benefits and/or constraints of each method covered
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Rig Selection – Workover Rigs
Tubing Conveying
Conventional Workover
(Completion Unit)Coil Tubing Unit
Hydraulic Workover Unit (Snubbing Unit)
Completion Unit, Service Unit, Pulling Unit, and Workover Rig – terms are interchangeable
Portable rig with a derrick
Rigged up over a well
Utilized to pull or run the completion string (conventional stick
tubing)
Rig Selection – Service Unit
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Intervention/Workovers – Workover Rig
Rig Selection – Workover Rig
Withstand different loads
Varying horsepower (HP)
Rated to different depths
Derrick heights
Rigs are Manufactured in Different Sizes
Normally Providedwith rig
• Crew
• Circulating pumps
• Slips
• Tubing tongs
• BOP
Rental Equipment
• Light plant
• Power swivel
Significant Amount of Ancillary Equipment
Service Unit
Has many of the same rigcomponents
Can rotate pipe
Smaller, less pullingcapacity, less pumpcapacity, and are muchmore mobile
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Workover Rig Diagram
Workover Rig – Application
Any workover where the completion string must be pulled
Well must be “dead” when the completion is pulled
Casing or tubing repairs Wellbore clean outs
Pulling or running artificial lift (AL) equipment
Cement squeeze jobs Vertical and horizontal wells
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Workover Rig – Killing the Well
Need the well “dead” (static) while performing the workover
Normally pump kill fluid into the completion string to maintain static condition in which to work
Hydrostatic head of the kill fluid must exceed the reservoir pressure to prevent the well from flowing during the workover
Workover Rig – Killing the Well
Objectives
Remove hydrocarbons fromwellbore
• To surface?
• Back into formation?
Replace with kill weight fluid column
Achieve stable/constant fluidcolumn
Protect the reservoir
• Minimize invasion
• Minimize damage
Risks and Key Factors
How to displace?
Safe overbalance level?
Minimize contamination
Efficient rather than quickdisplacement
Minimize losses
Minimize exposure time
If circulating, forward orreverse?
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Reverse Conventional
Well Killing Options
Bullhead
Circulate
Pump and bleed
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Bullheading
Packer Fluid
SSD (Closed)
Packer
Bullheading
Packer Fluid
SSD (Closed)
Packer
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Bullheading
Kill Fluid
Bullheading
Kill Fluid
SlightlyOverbalanced
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Bullheading – aka “Deadheading”
Conditions can make bullheading difficult in certain situations:
Concern for damaging the formation in conventional reservoirs and/or depleted reservoirs
Both, tubing and casing burst/collapse pressures, should be known and not exceeded. Sometimes, when bullheading down the tubing, pressure may have to be exerted on the casing in order to prevent the tubing from collapsing
Formation fracture pressure may have to be exceeded due to low reservoir permeability
Gas migration through the “kill fluid” can pose a problem
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Circulating Kill Fluid – Hydraulic Considerations
Hold additional back pressure (100–200 psi) until well stability is confirmed after kill circulation
Check anticipated frictional pressures and ensure frac pressures are not exceeded
Prepare kill graph ‒ allows effective control of choke backpressure
Prefer to isolate the reservoir with tailpipe plug
How to control losses?Continuously monitor the stability of the well and losses
Displacement rate – controlled but not too slow to prevent gravitational separation – settling or density drift
Preference is: Reverse circulate to kill Forward circulate to place cushion
and offload
Circulating Kill Fluid – Reverse Circulation
Packer
Packer Fluid
SSD (Closed)
Nipple in Tailpipe
Production Tubing
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Circulating Kill Fluid – Reverse Circulation
Packer
Packer Fluid
SSD (Closed)
Nipple in Tailpipe
Production Tubing
Circulating Kill Fluid – Reverse Circulation
Packer
Packer Fluid
SSD (Closed)
Nipple in Tailpipe
Production Tubing
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Circulating Kill Fluid – Reverse Circulation
Valve Opened
Kill Fluid
SSD (Closed)SSD Opened
Circulating Kill Fluid – Reverse Circulation
Near-Static
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Circulating Kill Fluid – Reverse Circulation
Packer
Packer Fluid
SSD (Closed)
Nipple in Tailpipe
Circulating Kill Fluid – Reverse Circulation
PlugWireline
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Circulating Kill Fluid – Reverse Circulation
Wireline
Circulating Kill Fluid – Reverse Circulation
PlugWireline
Plug in Nipple
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Circulating Kill Fluid – Reverse Circulation
Valve Opened
SSD (Closed)SSD Opened
Plug in Nipple
Circulating Kill Fluid – Reverse Circulation
Valve Opened
Kill Fluid
SSD (Closed)SSD Opened
Plug in Nipple
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Circulating Kill Fluid – Reverse Circulation
StaticPlug in Nipple
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Rig Selection – Workover Rig
Mobility
Ability to trip (i.e. run orpull) completion strings
Can rotate tubing
Can circulate throughtubing
Can “push tubing”therefore, can run sticktubing into horizontal wells
Can operate in sweet orsour environments
The least expensive of thetubing conveying rigs
Not utilized under live pressure
Must kill well to trip completionstring
More expensive than wireline
Longer trip times than wireline
Offshore rates are high
Offshore availability can be anissue
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Rig Selection – Workover Rigs
Tubing Conveying
Hydraulic Workover Unit (Snubbing Unit)
Coil Tubing UnitConventional Workover
(Completion Unit)
Rig Selection – Hydraulic Workover (Snubbing) Unit
Portable rig used to trip stick tubing under
pressure
Hydraulic system provides the force to snub the
tubing downhole against live pressure
Enables running and pulling of conventional (stick) tubing without
killing the well
Tripping a completion string of stick tubing
when one does not wish
Repairs to or replacement of completion string
Pulling TCP guns
Fishing
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Rig Selection – Snubbing Unit
Snubbing equipment layout
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Snubbing Unit ‒ Schematic of Components
Gin Pole
Basket
Extension
Torque tube
LadderTorque tube mount base plate
Slip windowWorkaround
Hydraulic Jacking Unit
Work Floor or Work Basket
BOP Stack
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Rig Selection – Snubbing Unit (HWU)
Allows workoverunder live pressure
Protects reservoirfrom potentiallydamaging kill fluids
Can perform any taskthat can be done withconventional unit
More expensive thanconventional workoverrig
Slower than conventionalworkover rig
Tripping pipe morecomplicated operation
More dangerous (fewerbarriers and pressure atthe surface)
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Snubbing Unit – Operation
Another popular method of stripping tubulars in/out of a wellbore iswith the use of an "Annular" Blow Out Preventer (BOP)
An Annular BOP consists of a natural or synthetic rubber elementwith encased metal reinforcement sections
Annular BOPs come in various sizes and pressure ratings and areideal for lower pressure gas wells
Generally, the maximum pressure for stripping pipe through anannular is equal to 40% of the maximum static pressure rating dryor 60% if the pipe is lubricated as it is being stripped through theannular
Traveling slips are used to help drive the tubing down againstpressure (this is called snubbing)
Stationary slips are used to hold the tubing string in place whileanother joint of tubing is added to or removed from the string
Snubbing Unit – Operation
Traveling Slips
Stationary Slips
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Snubbing Unit – Operation
Traveling Slips
Stationary Slips
Snubbing Unit – Operation
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Snubbing Unit – Operation
Snubbing Unit – Operation
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Snubbing Unit – Operation
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Snubbing with Pipe Rams and Coupled Tubing
Need to lower thetool joint throughthe stationary slipsystem
Stop tool jointabove topsnubbing pipe ramon stack
Step 1
• Tool joint above topsnubbing ram
• System alreadypressurized below top snubbing ram
Snubbing Animation
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Step 2
• Lower snubbingpipe ram is closed and well is sealed
Snubbing Animation
Step 3
• Preparing to bleedoff volume between upper and lower snubbing rams
Snubbing Animation
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Step 4
• Bleeding off the areabetween the rams –prepare to open upper snubbing ram
Snubbing Animation
Step 5
• Pressure bled offbetween rams/ upper ram open and preparing to lower tool joint into position between upper and lower snubbing rams
Snubbing Animation
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Step 6
• Tool joint in position
• Upper snubbing ramclosed
• Preparing topressure upbetween upper andlower snubbingrams
Snubbing Animation
Step 7
• Pressuring upbetween closed upper and lower snubbing rams
Snubbing Animation
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Step 8
• Lower snubbing ramopened
• Lowering tubing andtool joint below lower snubbing ram into well
Snubbing Animation
Step 9
• Tool joint above topsnubbing ram
Snubbing Animation
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Rig Selection – Coil Tubing Unit
Portable rig withcontinuous string ofsteel tubing coiled on areel
Reel moves with therig from location tolocation
Coil available in various lengths, diameters, wall thicknesses,and metallurgies
Affects coil’s strength, brittleness, and resistance to corrosion
Collarless tubing allows tubing to be stripped through rubberseal
Coil Tubing Unit – Applications
Running logging tools – E‐coil
Drilling plugs
Cut tubing Horizontal well work
Logging
Perforating
Stimulation
Shifting sleeves
Wellbore cleanouts – vertical and horizontal Nitrogen offloading
Circulating inside completion string concentrically to:
Spot acid
Spot cement for squeeze job
Kill well
Spot sand plug
Pumping chemical treatments(corrosion, paraffin, scale, etc.)
Running or pulling tools
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Rig Selection – Coil Tubing Unit
Can work under live pressure
Can work in vertical orhorizontal wells
Can work inside productiontubing, cased hole, or openhole
Tremendous number ofapplications
Manufactured in many sizes
Sweet or sour wellapplication
Mobility and footprint‐onshore
No rotation of tubing
More expensive than workoverrig
Smaller diameter coil can be raterestrictive – less annular velocity
Coil not as strong as stick tubing
Increased flexibility leads topotential buckling issues
Limitations to distance in lateral
Bending on coil and gooseneckcauses plastic deformation
Highway limitation issues
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Rig Selection – Application Summary
Rigs applicable to live pressure
• Wireline – with lubricator
• Snubbing Unit
• Coil Tubing Unit (CTU)
Rigs common for minor interventions & running tools concentrically
• Wireline
• CTU
Rigs common for major workovers
• Workover Rig
• Snubbing Unit
• CTU
Rig Selection – Application Summary (continued)
Rigs in which you can circulate
• Workover Rig
• Snubbing Unit
• Coil Tubing Unit
Rigs which can rotate tubing
• Workover Rig
• Snubbing Unit
Rigs which can “push” through deviated or high‐angle wellbore
• Workover Rig
• Snubbing Unit
• Coil Tubing Unit
• Electric line with tractor
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Well Intervention Summary
If wireline works, then use it
If conducting a workover and killing the well with kill fluids willnot damage the reservoir, then usually a workover rig is utilized
If conducting a workover and killing the well with kill fluids willlikely damage the reservoir, then consider a rig that allows one towork with live pressure (i.e., snubbing unit or coil tubing)
Select the rig that satisfies the SEE acronym – allows for the jobto be performed Safely, Efficiently, and Economically
Generalized Rig Selection Process
Planning the Workover – Covered in the Workover Fundamentals module.
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Back to Work Suggestions
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Do you have reliable production data? Do you have good reservoir pressure data?
Do you have average reservoir pressure data as a function of time which can be used as a proxy to determine the hydrocarbons in place?
Do you have good fluid properties measurements?
Do you have good correlations which we can use to predict the fluid properties?
Do you have reliable production data? Do you have good reservoir pressure data?
Do you have average reservoir pressure data as a function of time which can be used as a proxy to determine the hydrocarbons in place?
Do you have good fluid properties measurements?
Do you have good correlations which we can use to predict the fluid properties?
Course Title
Back to Work Suggestions
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Find the records of an intervention that was performed with braided wireline on a well in your area. Determine why braided line was used instead of slickline.
Was it successful? If not, why not?
Determine the comparable allowablework loads of each option (i.e., slickline vs. braided line).
Well Intervention Core
Back to Work Suggestions
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Do you have reliable production data? Do you have good reservoir pressure data?
Do you have average reservoir pressure data as a function of time which can be used as a proxy to determine the hydrocarbons in place?
Do ymeasurements?
we can use to predict the fluid properties?
Do you have reliable production data? Do you have good reservoir pressure data?
Do you have average reservoir pressure data as a function of time which can be used as a proxy to determine the hydrocarbons in place?
Do ymeasurements?
we can use to predict the fluid properties?
Course Title
Back to Work Suggestions
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Find the records of a workover that was performed in your area utilizing a snubbing unit. Ask the engineer that designed the procedure why a snubbing unit was usedversus a workover rig or a rig assist unit.
Determine if a rig assist unit wasconsidered for this job.
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Learning Objectives
This section has covered the following learning objectives:
Describe the main components of a conventional workover or completion unit
Describe the main components of a snubbing or hydraulic workover unit
Describe the main components of a coiled tubing unit
Compare and contrast the critical operational benefit and/or constraints of each method covered
PetroAcademyTM Completions and Workovers
Onshore Conventional Well Completion Core
Design Process for Completions and Workovers Core
Perforating Core
Onshore Unconventional Well Completion Core
Sand Control Core
Hydraulic Fracturing
Design Fundamentals
Well Completion Fundamentals
Formation Damage and Matrix Stimulation Core
Flow Assurance and Production Chemistry Core
Production Problem Diagnosis Core
Well Intervention Core
Workover Fundamentals
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