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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.

Well Intervention Core ═════════════════════════════════════════════════════════════════════════

© PetroSkills, LLC. All rights reserved._____________________________________________________________________________________________

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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




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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!




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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


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


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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The mass of the tool string moving upward delivers a sharp impact at the end of the stroke

C

Upward impact


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


Wireline Clamp

Alternate Braided Line Sealing

BOP

Rope Blocks

Wireline Clamp

Lifting Clamp


Line angle to be as close to 90°

Ginpole*

Hay Pulley

Weight Indicator


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


Plug Slickline

No Flow –Shut in at Surface



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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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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



Braided Wireline

Electric LineSlickline



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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



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


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


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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Packer

Packer Fluid

SSD (Closed)

Nipple in Tailpipe

Production Tubing


Packer

Packer Fluid

SSD (Closed)

Nipple in Tailpipe

Production Tubing



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Valve Opened

Kill Fluid

SSD (Closed)SSD Opened


Near-Static



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Packer

Packer Fluid

SSD (Closed)

Nipple in Tailpipe


PlugWireline



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Wireline


PlugWireline

Plug in Nipple



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Valve Opened


Plug in Nipple


Valve Opened

Kill Fluid


Plug in Nipple



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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


Traveling Slips

Stationary Slips



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Traveling Slips

Stationary Slips




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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 good fluid properties measurements?

Do you have good correlations which we can use to predict the fluid properties?

Course Title



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).






Do ymeasurements?

we can use to predict the fluid properties?



Do ymeasurements?

we can use to predict the fluid properties?

Course Title



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


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


Workover Fundamentals



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