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Wireline: Braided Cable, E-Line and Slickline Operations and Equipment George E. King April 2014 11/18/2014 1
Wireline: Braided Cable, E-Line and Slickline Operations and Equipment
George E. King
April 2014
11/18/2014 1
Contents
• Basic Wireline
• Surface Equipment & Pressure Control
• Best Practices
• Wireline Tools and Services
• Profiles & Plugs
• Pipe Cutting
11/18/2014 2
Slickline, Braided Line and E-
Line • Slickline – single strand wire. Mild steel. Sizes
0.072” to >0.125”
• Braided Line – multiple strand wire braided to form a cable. Non Conducting.
• Electric Line or E-Line – a multiple stand wire armor cable around a single insulated electrical conductor wire.
• Specialty cable – many forms of multiple conductor wire in insulated or armored cable.
Source 11/18/2014 3
Wireline Operations
• Common workovers with wireline
– liquid and fill tags
– gauge running and retrieval
– gas lift valve replacement
– sleeve shifting
– plug and packer setting
– bailer runs
11/18/2014 4
Critical Lesson
• Plugs must be equalized before releasing.
• Pressure may be trapped in many tool & wellbore configuration.
• Trapped pressure can propel a tool up the well very rapidly, causing wellhead & pipe damage and bird’s nests of wire that are extremely difficult and expensive to remove.
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Pressure
Differential
(psi)
3-1/2"
tube
4-1/2"
tube
5-1/2"
tube 7" tube
8-5/8"
tube
100 703 1253 1923 3737 4961
500 3514 6264 9617 18687 24807
1000 7027 12529 19234 37374 49614
5000 35137 62643 96172 186869 248070
Theoretical loads (in lbs) resulting from pressure differentials in various sizes of plugs.
The common element on all plugs that must be pulled is that there must be a reliable way to release the pressure below the plug before releasing the locking mechanism on the plug.
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Nominal Weight of Wire
Wire Size Wt per 1000 ft of wire
0.072 14 lb
0.082 18 lb
0.092 22.6 lb
0.108 31 lb
0.125 44 lb
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Selecting Wireline
• What devices have to be pulled (weights, loads)? • What impact forces are needed? • What are the tubing sizes?
– Small tubing – smaller wire, easier to work and recover. Easier to compress into a mass for retrieval.
– Large tubing – larger wire – stronger, less likely to birds-nest or kink, easier to fish as a single strand, but harder to compress into a mass when a wireline spear would work.
• Corrosion potential? • Local preferences?
11/18/2014 8
Wireline Surface Equipment
• Reels and Controls
• BOP
• Lubricators
• Grease (oil) Seals
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One view of a slickline unit’s controls -
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Typical slickline spool on a small unit.
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Slickline and Braided Line Drums
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Braided line – stronger (2800 to 3500 lb working strength, but
less “feel” when fishing and slower line speed.
Watch abrasion of steel by braided wire.
Harder to get a seal in stuffing box/grease injector
11/18/2014 13
Typical Wireline Rig-up
Wireline
Unit
Stuffing Box
Lubricator
swab valve
master valve
Lower
Sheave
Upper
Sheave
Springs
Slickline – Single Strand Wire, No
Conductor
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Schematic of a Grease Injector for Braided Line
Rubber Elements
Flow Tubes
Grease Injection
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SPE 27227
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Setting the Pack-Off Elements under
the top sheave, Top Sheave w/ isolation
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Stuffing Box – the Main Seal on the Wire
• Braided Line – Grease Injector
• Slick Line - Rubber elements with and without oil injection capacity. A hydraulic oil is usually used for sealing and lubrication of the wire.
• If a tool is to be hung-off on wireline, tighten the pack-off gland, but do not keep injecting grease – this will damage the well. you hang off a tool
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SPE 27227
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Wireline BOP
11/18/2014 22
Surface Rigup Considerations 1. Overall Safety
a) Height & Weight b) Pressure Control
i. Top & Bottom ii. Fit for purpose
c) Equipment Ratings d) Condition e) Pressure Test (?!?)
2. Lubricator a) Length – tools + 3 ft(?) b) Material? (H2S) c) Seals
11/18/2014 23
What Do Well Records &
Well Profile Tell You?
Is it Correct?
11/18/2014 24
Lubricator Layout and Loading Loading perf gun in lubricator
11/18/2014 25
Lubricator Length
• “Consider the tool string length when sizing the lubricator length. The available length to swallow a tool string is from the top of the swab valve to the bottom of the flowtubes. This length should be the TOTAL tool length, line head to bottom nose, plus 3 extra feet.”
11/18/2014 26
Wireline Fishing/Jarring Best Practices
• Maximum fishing time of 45 minutes to 1 hour before re-heading wire – move the fatigue point (fatigue caused by continual working over the sheaves during jarring) – usually cut off 100 to 150ft – depends on wire length that is working over the sheaves when jarring.
• Don’t be conservative about re-heading the wire – this prevents breaks and expensive fishing.
• Work to 50% of max load of wire.
• Use of 0.125 and braided wire considered?
11/18/2014 27
Some Wire Types
• Bright Steel – most widely used, not for H2S or CO2
• AISI 304 – H2S service
• AISI 316 - H2S service
• Note: make sure you know what wire is going in the well.
• Do a twist test and inspect the break on a routine basis.
11/18/2014 28
Wire Limits (Bright Steel) (estimates only)
Wire Size Minimum Tensile Strength Max Work Level (normal work level is lower)
0.072” 972 lb. 500 to 600 lb. ?
0.082” 1239 lb. 850 lb. ?
0.092” 1547 lb. 1000 lb. ?
0.108” 2436 1400 lb. ?
0.125” 3200 1800 lb. ?
Minimum tensile is 75% of rated break strength.
Data for “bright plow steel wire”
11/18/2014 29
Wire Limits - AISI 304 (estimates only)
Wire Size Minimum Tensile Strength MaximumWork Level
0.082” 1280 lb. 850 lb. ?
0.092” 1582 lb. 1000 lb. ?
0.105” 2070 lb. 1400 lb. ?
Minimum tensile is 75% of rated break strength.
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Wireline Weight – modeled and actual
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Wireline breaks involve fatigue, physical
damage to the wire, corrosion and other factors.
11/18/2014 32
Wireline Operations
• Advantages - speed, cost, footprint, “feel”
• Disadvantages – low wire strength
– lack of rotation
– lack of circulation
• Problems
–lack of experienced operator – poorly maintained units
– impatience
– poor well records
11/18/2014 33
Pulling Weight Into the Well – The Problems
• Long lubricators required
• Rig up height increased
• Added friction in deviated wells from longer weight stem
• Less wireline load capacity
• Often with large braided line, the well must be dead due to the pressure effect on the wireline.
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Common Problems with Wireline
• Wire breaks
– Fatigue (work hardening failure)
– corrosion (H2S, CO2, acids)
– load failure
• Damage to well equipment and coatings from wire abrasion
11/18/2014 37
Slick Line Torsion Tester - Twist testing has eliminated wire breakage
in many areas.
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Wire Fatigue – Number of turns to break wire – Alaska
• Wire Size New Min turns to break
– 0.072 29
– 0.082 26
– 0.092 23
– 0.108 20
– 0.125 22 18
11/18/2014 40
Slickline Stretch and Specs - GoM
Wire diameter
inches
Stretch due to
load (in/PT/100
lbs)
Sheave Diam.
inches
Diam.
Tolerance
Min. Twist
Number in 8”
length
0.092 0.00682 13 +/- 0.001” 21 min
0.108 0.00495 16 +/- 0.001” 18 min
0.125 0.00369 19 +/- 0.001” 15 min
Approximate stretch in inches due to load = ((stretch factor x
wireline length in hole (ft) x payload in pounds)/100)
Example: For a 400 lb BHA at 10,000 ft in a vertical hole using
0.108” wire, the approximate stretch is about 198 inches or 16-1/2 ft.
11/18/2014 41
Approximate Specifications and Load Limits for Slickline and Non Conductor Braided Line
Line Size inches
diameter
Min. Break
Strength
Max. Break
Strength
Operating at
65% of min.
0.092 1828 lbs 2020 lbs 1188 lbs
0.108 2455 lbs 2712 lbs 1596 lbs
0.125 3203 lbs 3534 lbs 2082 lbs
3/16 braided 6400 lbs 3200 lbs
1/4 braided 11400 lbs 5700 lbs
5/16 braided 16200 lbs 8100 lbs
11/18/2014 42
Look at the type of break
• Smooth – no problem
• Jagged – embrittlement possible, even if the turn count is within minimum tolerance, put new wire on the unit – cheaper than fishing a well full of wire. – Corrosion by H2S and CO2
– Fatigue mixed with embrittlement
Note – avoid running wireline in an H2S well if at all possible.
11/18/2014 43
Wireline Fatigue
• Limit the wireline crews to 50 - 60 jar cycles prior to POOH and cut of +/- 50m wire
11/18/2014 44
Some Very Basic Learnings
• About “90%” (maybe 99%) of success is in the operator selection.
• Wire line breaks can be almost totally eliminated by torsion testing of wire, limiting jarring times, only using a great operator and not pushing the limits with wire, cycles or time.
• When wire breaks, always expect a little wire above the rope socket.
• Whenever possible, run a fishing tool that has a release.
• H2S wells can be wireline nightmares
11/18/2014 45
Wireline Equipment Checks
• 1. Measure and record data for all equipment that goes in the hole.
– diameters of every component
– tool body lengths
– thread patterns of each component
– Tapers, shoulders, unusual equipment
– compressed and extended jar lengths
– Examine the catch shoulders of necks and grabs.
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Wireline Equipment Checks
• 2. Wire history & checks
– size, material
– use history
– corrosion treatment
– torsion testing (turns before breaking)
– jarring time in one spot (working continuously over the shieve or pulley thins and fatigues wire)
11/18/2014 48
Wireline Equipment Checks
• 3. Equipment
– working condition
– support for loads
– lubricator pressure limit
– seal equipment capability and backup
– seal equipment sizing
– Set screws (type, material, tightening, range of shear)
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Examine Everything Coming Out of the Well
SPE 141023
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Wireline Basic Equipment
• Rope Socket
• Jars
• Tools
• Wireline torsion testers
11/18/2014 51
Rope Socket Many types of rope sockets With selection often by operator preference. Small wires are the most common and the standard wrap method is by far the most common.
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There are many different types of rope rockets.
The number of turns in the wire influences breaking strength.
If wire breaks prematurely during rope sock makeup , do a torsion test.
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Junk in the bottom of a
well
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Jars
• Mechanical or spang jars – old design, but very effective – Mostly for near vertical wells, but have been used
in deviated sections (loses impact effectiveness as deviation increases) Roller stem is possible but not always practical.
• Hydraulic jars – Much slower acting
– Less (?) affected by deviation – still requires a tight wire above the jar.
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Fishing neck must be in
good shape with sharp
shoulders. Also, look for
any damage to threads.
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Hydraulic Jars
•Hydraulic Jars – initial problems.
- Problematic operation in gas & hot wells.
- Minimal impact forces due to short stroke length.
• Spring Jars were developed with longer stroke leading to
greater impact forces.
- Fixed spring value - jar had to be disassembled to change.
- Typically only 3 different values of spring available.
•Adjustable Upstroke Jar (PAJ) (Petroline- Weatherford)
• - Longer stroke leading to greater impact forces.
- Jar setting can be changed across a wide range and without disassembly.
- Disc spring stack design a highly efficient stored energy medium.
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Tools
• Stem
• Knuckles
• Various Tools
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Wireline Weight Stem
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Gauge ring cutters
Problems in highly
deviated wells - sticking
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Dimension should closely follow id of tube -
this allows check for partial collapse and
prevents material from getting on top of tool
string.
Camco 11/18/2014 67
CT Fishing Survey Tools
Tools and devices which help determine fish type and orientation
Lead impression blocks: Provide information on profile and orientation of the fish
Experience required to interpret recovered impression
Downhole cameras transmit images/video to surface: Clean wellbore fluid required
Temperature/time limitations
High cost of service? - often very valuable.
11/18/2014 68
Set down once and retrieve. Multiple set
downs only confuse the imprint.
Also known as a “confusion block” -
generally for good reason.
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Lead Impression Block Interpretation
Offset and
incomplete
impression
Fish lying on side
of wellbore
11/18/2014 71
Pop Quiz
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Some lead impression blocks may be made in various shapes
for assistance in describing shapes or locations of fish. Flat and tapered impression blocks
11/18/2014 73
Impression Block Best Practices
• Run a near drift block
• Set down one time and POOH
• Keep a file of paper cut-outs of pipe body diameters, connection diameters, tool connections, etc., that might look up. Helps to match the cut-out to the shape of the impression.
• Anytime an unusual fish is recovered, get a photo and a tracing of the ends – tools often break in the same area of the body.
11/18/2014 74
Other Specialty Tools
• Slickline tools mostly for plug setting and other manipulation needs, plus running memory gauges.
• Braded line is generally for running or retrieving heavy equipment.
• E-Line is most often used for data gathering operations.
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E-Line Tools
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Safety Switch for Explosive Devices.
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Stuck Pipe – Free Point Indicator
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Multi-Arm Caliper
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Damage Visualization
11/18/2014 81
Downhole video often much
better than impression
blocks for real information if
the fluid is clean & clear.
Cameras – down-looking and side looking. Mainly for problem identification and research.
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Uh? How? Cover the well when working above the wellbore!
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Vertical Fractures in open hole wells – Early research into fracture height and
orientation
Two inch by 1.5” view from a downhole TV camera run in clear water. Amoco - Circa 1971.
Fracture Growth Naturally Limited •Natural formation barriers. •Tectonic stresses in the rock •Leakoff into the reservoir. •Natural fractures that form complex or network fractures. •Typical frac height about 200 to 300 ft.
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Real Fractures – to scale Average Frac Width <1/16” to 1/8”.
11/18/2014 85
Slickline Tools
• Basic BHA (bottom hole assembly) – Rope Socket
– Weight bars (weight stem)
– Jars
– Tools • Running
• Retrieving
• Wire grabs
• Fluid tag – blind box
• Cutters, scrapers, rasps, swedges, etc.
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One type of running tool
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JD Pulling Tools – note sharp
shoulders and clean tool bodies
11/18/2014 89
JD Pulling tool – commonly run
just below the jar in the BHA.
JD type tools are used for external
fishing necks.
11/18/2014 90
The tops of fishing
necks are usually
tapered to assist the
fishing tool in locating
and attaching.
Note sharp shoulders
Note the extended body
of the neck – this
allows some extension
above the top of debris
that may settle on top
of the plug.
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Outside fishing neck with
flow through capacity.
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One problem with inside
fishing necks is that debris
may prevent the prong from
entering and latching.
11/18/2014 93
Inside fishing neck for a GS running tool
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Fish Type and Dimensions
•Many fishing tools only catch on limited size range (OD or ID)
•When dimensions of fish are known: – Prepare accurate fishing diagram
– Prepare wellbore or completion diagram
•Factors influencing selection of tools/techniques: – Fish stuck/free
– Fill or junk on top of fish
– Fish material properties • e.g. small ferrous objects retrieved by magnetic devices
11/18/2014 95
Fishing Diagram - Fishing Neck Detail
4.250 in. 3.500 in.
2.000 in. 1.500 in.
3.750 in.
2.313 in.
2.000 in.
1.813 in. Depth to top of fish
3455.50 ft
Wellbore tubular
Fish OD and length information
are presented in a general
fishing diagram
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The top of a gas
lift valve, bent
over in the
wellbore.
DHV Inc.
11/18/2014 98
Wellbore and Completion Geometry
•Minimum tubular or restriction size – Determines maximum OD of CT/toolstring which can be used
•When assessing drift clearances – Consider removal of fill
•Pressure differential may exist across the fish – Can force toolstring up or down wellbore
•When determining overpull available at fish – Consider wellbore geometry
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Bailer Bottom
Flapper in the bottom of the
bailer tube.
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Tools for running and retrieving gas lift valves
– note: maximum length of tools and valve or
dummy must fit into the tool body. Latching
too long a valve can stick assembly.
Detent finger on tool body – indexes tool and
orients for running and retrieval.
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End of Tubing Locator. Arm
is spring loaded and tucked
into the tubing with end
pointing upward. At end of
tubing, the arm is deployed
by the spring. It cannot
swing into the slot in the
body until it shears the pin.
It is normal to pin with a
small pin, perhaps even steel
– but watch the profiles and
unusual diameter changes.
11/18/2014 104
High Angle Wells
• Rollers
– Used for getting wireline assemblies into deviated wells.
– Most needed for heavy tool strings
– Can increase application of wireline into wells to over 80 degrees.
• Friction Reduction
– Chemical additives reduce friction by 30%
11/18/2014 105
Roller stem used in higher deviation wells.
Watch problems with deposits such as
scale, paraffins, and asphaltenes.
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Wireline Checklist – a few pointers
1. Check pipe connection and pressure rating of lubricator and BOP
2. Lubricator long enough for all the BHA with jars fully extended, plus maximum length of fish, plus a few extra feet?
3. Check mandrel profiles and other tools to be run for correct OD, profile type and function.
4. Check pressure equalization features on all pulling and retrieving tools
5. Check that running, pulling and fishing tools have the correct latch mechanism for the tool being run or retrieved.
6. Check wireline unit for proper function (engine, clutch and line)
7. Can you check the wire history? Especially important if the truck has been working in H2S areas.
8. Check wire with twist test for fatigue.
9. HPHT, especially sour wells, are wireline nightmares – find another way to do the job?
10. Have emergency plan for handling breaks and leaks.
11. Have the name of a wireline expert in your pocket.
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Tractor – Profile Cleaning
11/18/2014 109
Profiles or Nipples - problems
• Latch areas may be filled with cement, scale, corrosion products or other debris.
• Scrapes in the polish bore and a seal cannot be made.
• Wireline cuts may be common in deviated areas of the well, especially in kickouts.
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Example Tool String
• Record
– Each component
– Each thread type & diam.
– Fishing neck info of each neck.
– Notable wear or other damage
– Length & diam. of each component
– Total length & max diam.
SPE 141023 11/18/2014 111
SPE 141023
Debris in old wells……
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Corrosion in areas of the well prevent seal of most types of plugs
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Nippleless Plug Assembly
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Bottom Anchor tool – Before & After Setting
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Frac Sleeve & Removal of a Stuck Frac Sleeve
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SPE 141023
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Plugs and Profiles
• Types
• Running
• Pulling
• Problems
Plugs are set for many reasons – but mostly for isolation of pressures.
Not all plugs are a permanent seal. Sand plugs, cement plugs and inflatables have special requirements.
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Profiles (Nipples)
• Landing Profiles – provide a hones bore and locking recesses locking mandrels (plugs) to locate and lock in place. The specific mandrels can control flow or have other functions.
• Selective Profiles – allow several profiles of the same size to be run in a well. The mandrels can be run through the profile or set in the profile, depending on the design.
• No-Go Profiles – a profile with a restricted area at the bottom that stops larger tools from passing through the profile.
• Pinned couplings – a coupling with a pin across the diameter to prevent tool passage.
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Profiles
• Type S
– pre-selected landing location for subsurface flow equipment.
– Only locates (sets) in profiles with matching key position.
– Designed to withstand pressure from above or below.
– Floating keys to hold against fluctuating pressure.
• Type N No-Go
– Single nipple installation at bottom of tbg (selective nipples above).
– Full opening packing bore, locking recess at top, slightly restricted No-Go at bottom..
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Mandrels
• Type B, C, D and W mandrels – Pressure rating of 1,500 psi
– Packoff without a landing profile.
– Hold pressure from the bottom only, usually set at 1000 ft for tree repairs.
– Slip pack-off element is mechanically expanded with a running tool and packs off against the tubing ID.
– B mandrel uses choke cups
– C mandrel is set by upward jarring – shears a pin, allowing mandrel to move upward and expand the packing
– W mandrel compresses a sealing element against tubing ID.
– D is a collar stop – run with a running tool, designed to lock in API tubing collars in first upward movement. .
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Other Wireline set tools
• Downhole Regulators - Designed to reduce surface flow-line pressure to keep surface controls from freezing (hydrate formation).
• Pack-offs and anchors – a device that can be set anywhere in the tubing to straddle and pack-off holes. A type D collar stop is used at the bottom of the tool.
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A typical plug showing seals, equalization ports and locking keys
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Collar Stop
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X and XN Profiles
in. mm. lb/ft kg/m in. mm. in. mm. in. mm in. mm
2-3/8 50.3 1.995 50.57 1.901 48.29 1.875 47.53 1.791 45.49
2-7/8 73.0 2.441 62.0 2.347 59.61 2.313 58.75 2.205 56.01
3-1/2 88.9
4-1/2 114.3 12.7 18.97 3.958 100.5 3.833 97.36 3.813 96.85 2.62 66.55
Tbg Size Tbg Weight
Tbg ID
Tbg Drift Packing Bore
4.6 5.85
5.4 9.52
9.3 13.84
4.7 5.99
5.5 9.67
10.2 15.18
2.992 76
2.922 74.22
2.857 72.82
2.750 69.85
2.813 71.45
2.750 69.85
XN NoGo ID
2.666 67.72
2.635 65.93
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R and RN Nipples Size Wt ID Drift Packing Bore NoGo Lock ID
in. mm. lb/ft kg/m in. mm. in. mm. in. mm. in. mm. in. mm.
1.9" 48.26 3.64 5.42 1.5 38.10 1.405 35.69 1.375 34.93 1.250 31.75 0.620 15.75
2-3/8" 50.93 5.3 7.89 1.939 49.25 1.645 41.78 1.781 45.24 1.640 41.66 0.880 22.35
2-3/8" 50.93 5.95 8.85 1.957 49.71 1.773 45.03 1.710 43.43 1.560 39.62 0.750 19.05
2-3/8" 50.93 6.2 9.23 1.853 47.07 1.759 44.68 1.710 43.43 1.560 39.62 0.750 19.05
2-3/8" 50.93 7.7 11.46 1.703 43.26 1.609 40.87 1.500 38.10 1.345 34.16 0.620 15.75
2-7/8" 60.33 7.9 11.76 2.323 59.00 2.229 56.62 2.168 55.07 2.010 51.05 1.120 28.45
2-7/8" 60.33 8.7 12.95 2.259 57.38 2.165 54.99 2.125 53.98 1.937 49.20 0.880 22.35
2-7/8" 60.33 8.9 13.24 2.243 56.97 2.149 54.58 2.125 53.98 1.937 49.20 0.880 22.35
2-7/8" 60.33 9.5 14.14 2.195 55.75 2.101 53.37 2.000 50.80 1.881 47.78 0.880 22.35
2-7/8" 60.33 10.4 15.48 2.151 54.64 2.057 52.25 2.000 50.80 1.881 47.78 0.880 22.35
2-7/8" 60.33 11 16.37 2.065 52.45 1.971 50.06 1.875 47.63 1.715 43.56 0.880 22.35
2-7/8" 60.33 11.65 17.34 1.995 50.67 1.901 48.29 1.875 47.63 1.715 43.56 0.880 22.35
3-1/2" 88.9 12.95 19.27 2.75 69.85 2.355 59.82 2.562 65.07 2.329 59.16 1.380 35.05
3-1/2" 88.9 15.8 23.51 2.548 64.72 2.423 61.54 2.313 58.75 2.131 54.13 1.120 28.45
3-1/2" 88.9 16.7 24.85 2.45 62.23 2.355 59.82 2.313 58.75 2.131 54.13 1.120 28.45
3-1/2" 88.9 17.05 25.37 2.44 61.98 2.315 58.80 2.188 55.58 2.010 51.05 1.120 28.45
4-1/2" 114.3 12.8 18.97 3.958 100.5 3.833 97.36 3.813 96.85 3.725 94.62 2.120 53.85
4-1/2" 114.3 13.5 20.09 3.92 99.57 3.795 96.39 3.688 93.68 3.456 87.78 2.380 60.45
4-1/2" 114.3 15.5 23.07 3.825 97.16 3.701 94.01 3.688 93.68 3.456 87.78 2.380 60.45
4-1/2" 114.3 16.9 25.5 3.754 95.35 3.629 92.18 3.437 87.30 3.260 82.80 1.940 49.28
4-1/2" 114.3 19.2 28.57 3.64 92.46 3.515 89.28 3.437 87.30 3.260 82.80 1.940 49.28
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Non-Selective Nipples
Lock recess
Seal bore
No-go
A single non selective nipple is usually all that is run in a well and it is usually at the bottom.
11/18/2014 127
Selective Nipples
Lock recess
Seal area
Landing recess
Essentially full opening (about 0.1” less ID than pipe)
Allows running multiple profiles, each with same ID. Set is determined by running tool.
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S Profile with plug installed. Showing locking section.
11/18/2014 130
S profile, seal assembly in the polish bore section
11/18/2014 131
S Profile – locking section
11/18/2014 132
11/18/2014 133
XN (left) and X profile (right). X profiles allow several to be run in series in the string (same size plug passes through each). Only one XN can be run (on the bottom).
11/18/2014 134
XN (left) and XN w/ X-pin insert (right)
11/18/2014 135
11/18/2014 136
A ported profile and plug.
11/18/2014 137
Other Profiles
• Flow Couplings – – heavy wall tube, 1 to 6 ft long (0.3 to 2m), made
of high allow steel.
– same ID as tubing but similar OD to coupling
– protection from internal erosion and corrosion
– Used where excessive turbulence is expected • above and below some profiles
• above crossovers
• above bottom hole chokes
11/18/2014 138
Other Profiles
• Blast Joints –
– Similar to flow couplings but designed to resist exterior erosion and abrasion
– 3 to 20+ ft long (1 to 6+m)
– Used opposite perforations
– Used opposite annular proppant entry point
– Used in straddled intervals in dual completions
11/18/2014 139
Other Equipment
• Downhole Chokes
– a set diameter restriction in the tubing that takes some pressure drop downhole.
• Used for up-hole hydrate prevention by taking some expansion of gas (cooling) in the downhole area where insitu temperatures are higher.
• Used for production or injection limiting.
• Stabilize bottom hole pressures
11/18/2014 140
Downhole Choke
11/18/2014 141
Sliding Sleeves
closed
open
11/18/2014 142
Other Equipment
• Downhole Regulators
– a variable diameter restriction in the tubing that takes some pressure drop downhole according to the rate of flow.
• Used for up-hole hydrate prevention by taking some expansion of gas (cooling) in the downhole area where insitu temperatures are higher.
• Used for production or injection limiting.
• Stabilize bottom hole pressures at variable rates
11/18/2014 143
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Latch recess
“Pocket”
Port to annulus
Access to tubular Flow Path
Indexing Groove
Side pocket Mandrel for gas lift or chemical injection
11/18/2014 145
Seal Swelling Problems
• Gas permeation
• Solvent swelling of seals
11/18/2014 146
Swollen seals on a plug retrieved from 10,000 ft
Left – one minute after pulling from the well, Right – after sixty minutes
Seal swell happens mostly on the trip up the hole as pressure is released and gas tries to leak out of the seal. It is not usually a cause of sticking.
11/18/2014 147
Avoiding Profile Debris Problems
• Cementing - protect the nipple profile with a sleeve similar to an insert sleeve used in a downhole safety valve
11/18/2014 148
When Sand Fill is Present
• “There was some sand present in the well, which gave us difficulties to run in hole at 63 deg dev. The problem was overcome by flowing the well slightly while running in, thus creating turbulences around the tool to flush away "sand dunes" building up in front of the tool.” – Charlie Michel, BP
North Sea operations comments – However, watch the potential for sticking with the sand washed above the tool.
11/18/2014 149
The extension on the bottom of the plug (left side of picture) allows debris to fall through and away from the internal fishing neck.
11/18/2014 150
Equalizing Prong with marks to differential contact on steel or sand.
11/18/2014 151
Specialty plugs are available that will set in almost any type of tubular, regardless of the presence or absence of a profile, but a seal always depends on the integrity of the tubing in which the plug is set.
Schlumberger 11/18/2014 152
Slickplug - The Retrievable Bridge Plug
Available from 2 3/8” to 7”
nominal sizes
Pressure ratings in excess of 5,000 psi
working
Temperature ratings up to 350°F
Barrier for Tree change - outs
Contingency tubing plugging
Zonal isolation tool
Location of flow control devices
Upper Slips
Pack-off
Element
Lower Slips
Bow Spring
Equalising
Assembly
Pumpopen
Plug
Weatherford 11/18/2014 153
WRP Wireline Set Retrievable Bridge Plug
Retrievable Bridge Plugs
Features:
• Run and retrieved under pressure
• Straight pull to release
• Can be retrieved on coiled tubing
• Pressure differential is equalized with washover retrieving tool
• Electric wireline setting with industry standard setting tools
Used for isolating zones during fracturing, acidizing
or cementing operations or during wellhead
removal
Weatherford 11/18/2014 154
Composite Plug Data – Drillable
Plug Mkr
Plug
Type Plug Size
Csg wt
range
lb/ft
Max Csg
ID
Min Csg
ID Length
Max Rec
Temp
Max Pressure
from above
Halliburton Std 4-1/2" 9.5-13.5
4.09"
103.9 mm
3.92"
99.6 mm
28.62"
726.9mm
50-250F
10-121C
5,000 psi
34,474 kpa
Halliburton Std 5-1/2" 15.5 - 23.0
4.95"
123.7 mm
4.67"
118.6 mm
29.09"
713.9 mm
50-250F
10-121C
5,000 psi
34,474 kpa
Halliburton HTHP 4-1/2" 9.5-13.5
4.09"
103.9 mm
3.92"
99.6 mm
27.92"
709.2mm
50-350F
10-177C
10,000 psi
68,947 kpa
Halliburton HTHP 5-1/2" 15.5 - 23.0
4.95"
123.7 mm
4.67"
118.6 mm
29.87"
758.7 mm
50-350F
10-177C
10,000 psi
68,947 kpa
Note the temperature limits. These have proved optimistic in a few HT wells. Milling time to remove these plugs with CT milling tools will be about 1 hour or less with the right mills, equipment and operator.
11/18/2014 155
Example of the force generated by pulling a plug without equalizing pressures below and above the plug
2500 psi
500 psi
5-1/2” Csg 4.95” ID
Effective area of plug = p id2/4 = 19.24 in2
Do a net force balance:
upward: 2500 psi x 19.24 = 48,100 lb
downward: 500 psi x 19.24 = 9,620 lb
Net force (upward) = 38,480 lb
Now, what happens if plug anchors are released before pressure is equalized? With wireline as pulling tool?
11/18/2014 156
Swab/Surge Forces
• “Plunger force” - tremendous force exerted event in small movements because of large area affected.
• Close clearances and high tool movement speeds increase the swab/surge force
• Circulation while pulling lessens swab/surge loads
11/18/2014 157
Laying Sand Plugs
• Shut-in well for several hours to prevent crossflow disruption of plug.
• Don’t bury the BHA with dumped sand
• Tag frequently to avoid over-fill
• Use a gell spacer in front of sand to prevent sand roping or falling down the hole. Rapid sand fall out can cause bridge off inside the CT.
11/18/2014 158
Sand fall rates in various fluids
10/20 mesh Bauxite 20/40 mesh Bauxite
Fluid ft/min m/min ft/min m/min
WF220 14.4 4.4 4.1 1.2
WF240 4.1 1.2 1 0.3
WF260 1 0.3 0.24 0.07
Diesel 33.7 10.3 16.9 5.2
Water 33.7 10.3 20 6.1
10/20 mesh sand 20/40 mesh sand
Fluid ft/min m/min ft/min m/min
WF220 7.5 2.3 2.2 0.67
WF240 2.05 0.62 0.49 0.15
WF260 0.49 0.15 0.11 0.03
Diesel 21.9 6.7 10.2 3.1
Water 21.9 6.7 12.6 3.8
Source – D/S Field Book 11/18/2014 159
Setting a cement plug
• Position
• Setting in mud
• Effect of fluid loss and cross flow
11/18/2014 160
Setting Cement Plugs
• A near 100% reliable system if cross flow can be stopped.
• Most cement plugs fail because of cross flow, density and viscosity mismatch, or failure to “break” the fluid momentum.
• Full plug method described and field tested in SPE 11415 (published in SPE JPT Nov 1984, pp 1897-1904) and SPE 7589.
11/18/2014 161
Cement Plug Failure
Many cement plugs fail for the same 4 reasons:
1. Cross flow cuts channels into the plug.
2. Cement is higher density that the mud.
3. The mud is much lower viscosity than the
cement slurry.
4. The open ended tubing produces a high
momentum energy condition that the mud
cannot stop.
The result of the last three is that the cement is
spread out along the hole and a plug is never
formed. Ideal Reality
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How?
1. Use a simple tubing end plug with circulation to the
side and upward but not downward.
2. Spot a heavily gelled bentonite pill below the cement
plug depth. Pill thickness of 500- 800 ft (152- 244 m).
3. Use a custom spacer to separate the pill and the
cement slurry.
4. Use a viscous, thixotropic cement with setting time
equal to the job time plus ½ hr. Plug thickness of 300
to 600 ft (91 to 183 m)
5. Rotate the centralized tubing (do not reciprocate)
during placement and gently withdraw at the end of
the pumping.
6. WOC = 4 hrs for every 1 hour of pump time.
Full details and field tests in SPE 11415.
Bentonite Pill
mud
Cement
11/18/2014 163
Diverter Plug on End of Tubing
A simplified diverter tool can be made by
plugging the end of tubing and drilling 8 holes
– the bottom four straight out and the top four
angled up at 45o.
Holes are 0.75 to 1” (2 to 2.5 cm) diameter.
SPE 11415 11/18/2014 164
1. Modify the tubing to bull plug the bottom and open a side port 2. Pump a 20 bbl pill of heavily gelled bentonite, same density as the mud in the hole 3. Spot the cement slurry on top of the pill while slowly withdrawing the tubing.
11/18/2014 165
Pipe Cut-Off • Methods
– Explosive (shaped charge)
– Linear (cutting the coupling)
– Chemical
– Radial Torch (thermite plasma)
– Mechanical
– Abrasive
• Targets
– Pipe, usually tubing, when pulling a packer
– Tailpipe
– Special Targets • Multiple strings
• Casing recovery
• Exit windows (experimental)
11/18/2014 166
Shaped Charge or Explosive Cutter – note remaining flare – may require milling in some cases. The flare in on both ends of the pipe at the cut (up-looking and down-looking. Clearances must be considered or pipe sticking will be a problem.
Problems: getting a large cutter (80% of ID suggested) to the target, flare remaining after cut, outside pipe damage.
Shaped continuous and segmented cutters
Failure to cut the pipe is common when the cutter is less than about 75% to 80% of the ID of the pipe. Shaped cutters also fail more often: 1. in higher strength pipe, 2. in thicker pipe, 3. in jewelry (thicker and higher alloy), 4. where tension can not be exerted, 5. in some higher temp applications.
Cuts are rarely complete: over-pulls (tension applied in excess of the cut string weight) of 20,000 to 50,000 lb are common to pull the last small pieces of the pipe apart.
11/18/2014 167
A Split-ShotTM charge fired in a coupling. If depth control is accurate and the coupling is not a hook design, a high success rate is expected, however, clearances and over-pulls are often necessary. Hook threads resist separation of pin & box.
Thread type is critical. API threads are much easier to separate with these tools than some premium threads.
A linear cutter – focuses on the coupling
11/18/2014 168
Chemical Cutters: Field data indicates that about 75% of these cuts are successful in separating the pipe on the first firing if: 1. tension can be exerted at the cut point, 2. there are no coatings (plastic, wax, rust, etc.) inside
the pipe, 3. depth is less than about 10,000 ft, 4. pressure is equalized between the annulus and
tubing before the cut is attempted. 5. the pipe is not a high chrome alloy, 6. the person applying the cutter is experienced.
Most often, the cut is through about 95% of pipe wall. Separation of the pipe very often requires over-pulls of > 30,000 lb. The minimum restriction about the cut point is one of the most important limiting factors in getting a reliable cut.
Chemical Cutters A chemical cut – note the jet-produced indents at the cut from nozzles spraying the bromine tetra-floride reactant against the inside of the pipe.
A Near Perfect Chemical Cut. 50k over-pull dropped off immediately when cutter fired. One joint in the string above cut was found to be partly backed off 4-1/2 turns on pulling tubing.
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Chemical cutter deployment – critical actions are:
1. Select correct cutter body diameter (75% to 80% of pipe ID at the cut,
2. Select a new tool body (nozzles wear with re-use – enlarged nozzles are less efficient at focusing the stream on the inside walls of the pipe),
3. Centralization (perhaps including anchoring),
4. Punch a circulation hole and allow pipe and annulus pressures (and fluid levels) to equalize),
5. Select a cut area away from couplings and coatings or deposits,
6. Place the target area of the pipe in tension of +/- 30,000 lb before the cut.
Chemical cutter – selecting the target and positioning the tool
11/18/2014 170
The focus of the fluid stream is spread out and the cutting ability of the chemical cutter is diminished as the distance from the tool body (exit point of the jet) increases. Proper tool diameter and centralization are critical.
The importance of the tool diameter
Below: the cutter body below the centralizer and above the lower reservoir for the cutting fluid. Note the jets in the tool arranged to spray the cutting fluid onto the wall of the pipe.
Right: A typical cut – about 95% of the pipe body is severed – no flares, but some over-pull will be required.
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After the chemical cut
After a successful cut. Note the location of the nozzles and the cut area directly offset from the nozzles. This cut, in 3.5”, S-135, 13.5 lb/ft drill pipe was in a test pond. The centralized cut achieved about 95% cut of the pipe body.
11/18/2014 172
Right: Tubing with incomplete chemical cut The remaining steel must be yielded by over-pull which was not possible with this cut in this application.
Note the nozzle holes in the pipe from the cutter. This particular application involved depths greater than 10,000 ft, high alloy pipe and a reportedly smaller than desired cutter.
Chemical Cutter Problems There are many factors that can defeat any type of cutter. Failures are due to many problems including small tool diameter, moving well fluids, pressure, temperature, depth and pipe grade.
Left: a mechanical cut pipe – note the large amount of debris. This type of coating would likely prevent even cutting of a pipe with a chemical cutter.
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A test of casing damage produced by a chemical cutter when the tubing target was pressed against the wall of the casing. The lateral groove on the inside the casing wall was approximately 0.15” (3.8mm) at the deepest point and about 4” (10 cm) in length.
Other Problems
11/18/2014 174
Radial Torch Cut, 13Cr 85 ksi pipe
A Radial Torch Cutter uses thermite – an aluminum powder burned to create temperatures capable of melting steel. The mixture is expelled and focused through nozzles onto the pipe wall to create a cut.
The thermite tools are useful for high allow pipe and for depths and pressures at which chemical cutters lose reliability.
Radial Torch Cutters
BP
11/18/2014 175
Abrasive Cutting • Abrasives can easily cut most steel and multiple layer
cuts are possible.
• Control of the cut may be difficult and outside pipe (nested strings) may be damaged or completely cut.
• Back pressure slows the cutting performance with significant drop in performance above 1500 psi backpressure.
• Nozzle performance is less affected by standoff when using abrasives.
Right: Single and multiple pipe layers cut by abrasives.
Below: a hole in the target pipe produced when a cut-off tool stopped rotating during an abrasive cut-off tool test.
Left: two cuts in the casing outside the target pipe. The one on the lower left is the hole produced when the tool stalled. The groove in the middle was produced after the tool successfully severed the target pipe and in the 20 seconds before the tool was stopped.
11/18/2014 176
Above: two bladed mechanical cutter. Blades pump out with pressure, must be held out and motor powered by the same flow. Must be anchored.
• Best choice for pipe where no tension can be pulled. • Anchor the tool to keep blades from “cutting threads” and moving up or down the pipe. • Minimize the number of cutter arms to insure good load application of cutter and use cutters with sturdy arms. • Often is the slowest form of pipe cutting – typically 1 to 10 hours to get a cut with the smaller tools.
Mechanical Cutters
Left: cutter blades retracted into the body of the tool.
Right: A mechanical cutter with smaller, shaped arms. These arms may cut quicker but may not be strong enough to avoid breaking in the more severe applications.
11/18/2014 177
String Shot Techniques
• Aid in back-off and jump-out of coupling. May also be useful in rattling the pipe to knockoff scale and free sticky pipe.
• String shot specifics – 1 to 4 strings of 90 grain (nominal wt) detonation cord, 3 to
4 ft long, suspended with E-line, across a coupling. – Use of more than 4 pieces of detonation cord may cause
pipe deformation or failure. – Initiated high order with the same type of caps used in
perforating. – Pull 25k+ over-pull into pipe or torque the pipe from
surface when doing a back-off. – The technique is very experience dominated.
11/18/2014 178
References and Text Notes
• Cutters
11/18/2014 179
Chemical Cutters The steel to be cut should be free of scale, oil, wax, plastic or other coatings. Many of the coatings are resistant to the cutter fluid and can result in partial or no cut. The tool should be centralized and anchored. Any movement of the tool during spraying of the cutter fluid smears the fluid impact and dilutes the effectiveness of the cut. Selection of the optimum diameter of cutter. Efficiency of the cut depends heavily upon the distance between the nozzle and the wall of the tubing. If the cutter is too small due to restrictions in the tubing string, the cutter will not cut the tubing. Application of tension is usually needed to finish the separation of the pipe. Usually, only 90 to 95% of the pipe wall body is cut during the firing of the cutter; the remainder of the tube body must be yielded by tension. Higher strength alloys, chemically resistant alloys, thick pipe and coatings on the inside surface of the pipe are challenges. High alloy (above S-135) and thick wall pipe should usually not be attempted with a chemical cutter. The cutter should be placed to avoid the coupling. Deep tubing cuts (cut depth greater than 15,000 ft) are not usually successful. Pressure and temperature may be reasons. The chance of a successful first cut on pipe above the packer is 75%, with 50% of the failures resolved by a second attempt. When tension cannot be pulled into the pipe (i.e., below the packer) , the chance of success on the cut is about 25%. Local variances and operator expertise are major factors.
11/18/2014 180
Shaped Charge Cutters • The cutters work by focusing a ultra-high pressure, directed, explosive pulse against the pipe wall.
The cutter is a close relation to a perforating charge and are unaffected by most coatings. The draw back to an explosive cutter is the flare produced at the cut area by the detonation. Early cutters produced large flares (20% pipe diameter growth or more) and broken sections of pipe. Later cutters (last 2 years) have been re-engineered to produce less than a 10% flare and no ribbons or splits. a. Selection of the optimum diameter of cutter. Efficiency of the cut depends heavily upon the distance between the base of he charge and the wall of the tubing. If the cutter is too small due to restrictions in the tubing string, the cutter will cut only one side of the tubing. b. The tool should be centralized if possible. This is not as critical as with a chemical cutter. c. Application of tension is usually needed to finish the separation of the pipe. Usually, only 80 to 95% of the pipe wall body is cut during the firing of the cutter; the remainder of the tube body must be yielded by tension. e. Higher strength alloys, chemically resistant alloys, thick pipe and coatings on the inside surface of the pipe are challenges. High alloy (above S-135) and thick wall pipe should usually not be attempted with an explosive cutter. The cutter should be placed to avoid the coupling. f. High temperatures may create problems with explosive cutters. The chance of a successful first cut on pipe above the packer is the same as with a chemical cutter: 75%, with 50% of the failures resolved by a second attempt. When tension cannot be pulled into the pipe (i.e., below the packer), the chance of success on the cut is about 25%.
11/18/2014 181
Linear Cutter
The linear cutter is a linear piece of shaped charge that can be run through restrictions and still make effective cuts in the coupling. The cutter is a straight tube with the linear charge running lengthwise. The tool is placed in the collar or tool joint and shot through the pipe and the coupling, weakening the connection sufficiently to allow pulling out at 5,000 to 10,000 lb. tensile force. The charge strip is held in a magnetically decentralized tool and is run on wireline. The advantage of the tool are its smaller diameter (1-11/16” and smaller) that will pass many obstructions. Tube tension during cutting is still recommended. The tool is best suited to upper pipe recovery operations. The split coupling would hamper fishing operations on the lower tubing. Critical Factors: a. The tool is only effective if shot in the coupling. b. Accurate depth control (within inches) is a must. A minimum length of 18” is suggested. Reliability is directly proportional to depth control accuracy. Hook wall threads and high loads may affect performance. When shooting with the pipe in tension (above the packer) and accurate depth control, the field reliability is about 90%.
11/18/2014 182
Abrasive Cutoff • Abrasive Cut-off – The development of abrasive cut-off tools is an outgrowth of the abrasive
perforating process that uses a sand and fluid slurry directed at the tubular and pumped at high rates. Tubular cut-off requires a rotating nozzle on coiled tubing or rotating the workover tubing. The mechanism can be used to cut nearly any weight or grade of tubular. Drawbacks are need for a fluid supply path (coiled or jointed tubing) and potential damage to the strings beyond the first pipe. Critical Factors: a. Although the proper standoff from the nozzle to the tubular wall is important, a cut can be made with several inches of clearance. b. The tool must be anchored. c. The tool head must rotate to provide a complete cut. If the tool stalls, a hole can be cut through tubing and casing. d. Back pressure increases the time needed to make the cut. Experimental application of the tool in 3-1/2”, 13 lb./ft, S-135 DP has resulted in average cut times of 3 minutes at surface conditions but may require 10 to 20 minutes downhole. d. Sufficient solids must be pumped to achieve cutting. Solids may be of various types, including sand, calcium carbonate and other materials. The more angular particles (like sand) will cut quicker than round, softer pellets like limestone.
11/18/2014 183
Thermite
• The tool sprays a thermite derivative (5000F) from shaped nozzles at the wall of the tube. This device is used for higher alloy tubing.
• The impacted surfaces are melted. Incomplete cuts and misfires have been the major drawback. Critical Factors: a. Nozzle condition. Reuse of nozzles is not suggested due to wear. b. Nozzle to pipe wall clearance.
11/18/2014 184
Mechanical Cutters
• Mechanical cutters – These mill-like devices, rotated by tubing or downhole motors are, at best, slow in cutting heavy wall or high allow pipe. Tubing cut times are 4 to 6 or more hours for cutters driven by small motors. Critical Factors: a. Ability of the tool to stay in one place (anchoring required), b. Hydraulics at the tool. Note that most of the cutters are run on coiled tubing c. Mill selection and mill bit breakage. Observed reliability is generally less than 50% for cutting with small tool BHA’s.
11/18/2014 185
Electric Line – Wireline Cable
• Cable Head Source: Quality Wireline and Cable
11/18/2014 186
Wireline Sheave Problems
11/18/2014 187
Wireline Sheave Selection
11/18/2014 188
Other Wireline Topics
• Drum crush and proper winding
• Armor design develops a torque proportional to the load on the cable. The torque of the outer wires is always greater than the opposing torque of the inner cable wires (more armor on outside).
• No standard rules for servicing alloy cables but they do need the have the armor tightened periodically (10 to 20 runs?).
Source: Quality Wireline
11/18/2014 189
Wireline Strength (Adapted from Quality Wireline & Cable inc.)
• All cables that become loose, & particularly new cables, are more susceptible to damage from: – Drum crush
– Outer wires being milked into a “bird cage”
– Reduced break strength
• Breaking strength of a cable comes from all inner and outer wires combined. When a cable becomes loose, the load is shifted from all the wires to only the inner wires – drastically decreasing strength.
11/18/2014 190
Why Does the Armor Get Loose?
• All cables in oil field service generate a torque directly proportional to the load on the cable.
• Torque of outer wires about 2 times opposing torque of inner armor (more wires outside).
• The greater the wire speed, the greater the torque and the higher the force that creates an unwinding stress.
• Lowering the cable into the well will partially offset the tension-produced unwinding force.
• There is more “recovery” at a slow speed into the well than a fast speed.
• Will pumping the wireline into a horizontal well negate the “rewind” forces and increase tendency for outer armor to loosen?
Source: Quality Wireline
11/18/2014 191
Cable Preservation Factors
• While running into the well, do not allow tension at any depth to fall below 2/3rds of the static tension at that depth.
• Come out at a speed not greater than omne that produces a tension of more than 1-1/3rd (133%) of static tension at that depth.
• Do not make up hydraulic pack-off overly tight. • Flow tube clearance of 0.004” to 0.006” • Temperatures within operating range of cable
components (caution on poly-cables).
Source: Quality Wireline
11/18/2014 192
Cable Tests?
• Tell-tale signs of cable being loose. – Cable will not lay straight on the ground – Put a paint mark on the cable and see how many
rotations the cable makes as it is rewound (from laying flat on the ground) – more than one rotation means the armor needs to be tightened.
– Top sheave turns sideways when tension is backed off indicating torque in the line.
– Sour Service lines loosen very easily and should be tightened after every job.
• When the armor is loose, the cable is at high risk and should be taken to a service center.
Source: Quality Wireline
11/18/2014 193
Equalization: Melting / Parting of Wire
• When pressure in the lubricator is equalized to well pressure before a run, the compression of the gases inside the lubricator will produce severe heat if the equalization is too rapid.
• In extreme cases, the conductor in the wireline has been melted, or the cable has broken or wires have been made brittle (armor may appear burned).
• Generally occurs within 1 to 2 ft of cable head.
Source: Quality Wireline
11/18/2014 194
How Fast is Too Fast for Equalization?
• When air filled lubricator is pressured from atmospheric (15 psi) to wellhead pressure (say 3500 psi), heat is generated.
• Location of max heat is top 12” of the lubricator – generally location of cable head.
• With air compression alone, temperatures can go over 1200oF. If pressurization is more rapid than the heat can dissipate or the pressure can escape past the clearances in the flow tubes, conductor and wire can be damaged.
• The more air that is in the lubricator, the more heat that can be generated. Large lubricators raise possibility of a problem.
• Mitigation: – Slow equalization - allow time for heat to escape.
– Filling lubricator with liquid prior to equalization reduces air volume & heat.
– By-pass valve is a possibility if it can be activated remotely.
Source: Quality Wireline
11/18/2014 195
Can a Too-Fast Equalization Create a Small Explosion?
• In extreme cases, where the lubricator is filled with air & equalizing gas from the well is hydrocarbon with trace of liquids, then a “diesel” ignition might result with very high temp & press – could damage or even rupture the lubricator.
=> <=
Source: Quality Wireline
11/18/2014 196
Flow Tubes
• In order to maintain control during a live (well pressure at surface) well operation, the cable is surrounded by a series of small tubes 0.004” to 0.006” larger than the wireline diameter.
• Grease is injected at gaps between tubes to complete the dynamic (moving) seal.
• Specialty greases are sold for certain temperature, pressure and corrosive environments.
• If a wire line is stopped for long periods (maybe to hang off a pressure gauge), then a rubber pack-off (at top of lubricator) can be tightened around the wire to minimize grease loss to the well (grease is very damaging to the reservoir).
Source: Quality Wireline
11/18/2014 197
Pack-off for Wireline
• Pack-offs are for use on wireline that is stopped for long periods of time.
• Using the pack-off to wipe the cable will cause accelerated wear to the pack-off elements. Use a properly adjusted, fit-for-purpose wiper instead.
• Over-tightening the pack-off will damage the wireline.
Source: Quality Wireline 11/18/2014 198
Crossed Armor Wires
• A common problem with flow tube use is "crossed" wires resulting from twisting wires together as the cable is threaded through the tight-fitting flow tubes. If the wires are not properly straightened out , the crossed wire may cause: – wear in the flow tube – damage to the wire while traveling through the tube – wire breakage - breakage can cause a wire ball below a
restriction – loss of seal in the flow tube – a crossed condition can travel up the wireline.
Source: Quality Wireline
11/18/2014 199
Sinker Bars – Why & How Many?
• Sinker bars are weights used to overcome the friction in the flow tubes and wipers and to offset the effect of pressure against the cross-section of the wireline. Larger wirelines and higher wellhead pressure require more weight bar weight.
• Formula
11/18/2014 200
Wireline in Corrosive Environment
• Slide under construction
11/18/2014 201
Seasoning New Cable
• Slide under construction
11/18/2014 202
Running wireline in a flowing well or allowing well to start flowing when wireline is in the well.
• Avoid flowing well when using wireline if possible.
• Do not flow well or severely curtail: – on tool string entry and until tools reach 400 to 500+
feet in the well. – When perforating a high pressure zone where the
tools could be blown upwards in the well. Sinker bars are often required.
– Where the tools are passing a severely restricted area and the inflow is below the tool string.
– In high flow rate wells.
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Electric Line – Wireline Cable
• Testing For Wear 1. Cut back 50 feet of cable from the whip end. 2. At this point take a two foot sample and inspect for any mechanical damage or unusual properties 3. Remove the outer armor wires 4. Clean the outer armor wires 5. Using a set of dial calipers (micrometer or vernier calipers) measure diameter of the individual wires
at the narrowest point (flat spot) and at the widest point. A minimum of six wires is recommended 6. If the wire has lost 12 - 15 % of its original diameter, then cable needs to be cut back farther. 7. Cut back 100 to 150 feet and re-inspect by following steps 2 through 6.
• Testing For Ductility (Once the cable has been verified to have an acceptable amount of metal left
on the outer armors) perform the ductility test as follows: 1. Cut approximately one foot from the wire sample. 2. Bend about 3” of the wire 90 degrees and place the short end in a vice 3. Wrap the long end around the diameter of the short end tightly making slow turns. 4. Once you have made five complete wraps, slowly unwrap the wire. 5. Inspect for any breaks or cracks. 6. If the wire breaks or cracks, cut back and re-test, by repeating steps 2 through 5.
Source: Quality Wireline and Cable
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Recovering Stranded or Bird Caged Wireline (with data from Elmar-Varco)
• Stranding is one of worst mechanical outcomes from wireline work.
• Stranding is a condition created when armor wire breaks or moves substantially, preventing any part of the wireline and/or tool string from being removed from the well and the valves below the string from being closed.
• If the wireline sticks in this way, it results in a potential well isolation problem.
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Stranded Wire – Recovery Spotting the Problem.
• See best practices fro prevention – prevention always preferred to recovery techniques.
• Indication of a stranded cable:
– During POH when cable tension increases for no apparent reason.
– When operator notices a broken or missing wire during spooling.
• Loose armor, highly worn wires, corrosion damage, H2S service may precede the problem.
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Source: Elmar – NOV
Stranded Cable – Recovery First Steps
1. Stop the cable immediately (minimizes size of the stranded cable “ball”). 2. Close the wireline valves on the BOP 3. Bleed pressure off the lubricator 4. Monitor pressure for at least 15 minutes 5. Ensure BOP is holding pressure before removing lubricator. 6. Pump great between wireline valves if you are on a gas well 7. Raise the lubricator a few feet – attach cable clamp. 8. Do not allow cable to splip through wireline valves (damage) 9. If possible use a flow diverter (sits on top of wireline valves & has a
clamp). 10. Slack off cable and check that clamp is holding. 11. Pull cable down through the control head and inspect damage.
Special equipment & procedure required when using a single lift rig-up on a workover /mast job, or if using a turn-around sleeve.
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Stranded Cable Condition of Wire
• There may be a ball of stranded cable caught under the control head. This must be removed from the lubricator.
• Cut deformed, kinked or otherwise damaged wire away with sharp wire cutters.
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Stranded Cable Repair
1. Pick-up the excess slack until cable just begins to come under tension.
2. Carefully unwrap each of the damaged strands 3 or 4 turns, but do not bend wires back from the cable.
3. Make a clean cut, smooth and taper the end of the strand with a file and lay the strand back in the cable armor.
4. If necessary, put a very slight bend in the end to make sure the cut end points into the cable.
5. Smooth with a file any protruding excess. 6. If more than one strand is damaged, ensure the strands
are terminated at widely spaced intervals. 7. Instant glue can be used to hold the strand in place.
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Stranded Cable Retrieval
1. Pickup Full Tension 2. Remove Cable clamp 3. Reconnect lubricators, pressure up & equalize. 4. Once lubricator equalized, open wireline valve & recover
wire slowly. 5. Monitor tension to & check to see if the damaged section
can pass through the flow tubes easily. • The whole process may need to be repeated several times
until successful. • If the cable damage is too severe, this approach may not be
used because of strength loss to the cable in relation to the weight of the cable and tools still in the well.
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Stranded Cable Severe Damage Case
1. Cut the cable as high as possible above the wireline valve (must be enough cable to feed through the flow tubes).
2. Taper the wire to pass through the flow tubes. 3. Cut off the damage cable from the winch side as well. 4. Lay down pressure control equipment 5. Remove one or more sections of lubricator. 6. Thread cable from the well through the pressure control head from the bottom. 7. Tie a reef knot (square knot) or preferably a sheet bend knot between well end
and winch end of the cable past the top sheave. 8. Pick up remaining lubricator, pick up slack, remove cable clamp, attach lubricator,
equalize slowly, open wireline valve and start spooling cable slowly. 9. After a few hundred feet of cable has been recovered – the lubricator that was
removed should be added, following same steps as when damaged cable was removed.
• If using a crane, starting with a short lubricator, or where the knot will not pass over the sheave, then these step might have to be repeated to get enough cable free to tie the knot on the winch side of the top sheave.
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When to Cut-Back Wireline Cables
• Openhole and Cased Hole
• Slide under Construction
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A Few of the More Common Wireline Tools
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