CT Fishing and Jetting Operations – Coiled Tubing

CT Fishing and Jetting Operations –

Coiled Tubing

• Free Point

• Fishing with and for coiled tubing

• Jars

• Impact tools• Impact tools

• Jetting basics

8/25/2015 1George E. King Engineering

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Impact Tools

• About 70% of CT operations include cleanout

• (including application on H2S, high temps,

hostile fluids and press)

• Impact drills offer alternatives to motors in • Impact drills offer alternatives to motors in

these environments


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Impact Tools

• Impact tools offer rotation. Tools designed to

give a twisting, downwards blow somewhat

like a jar. A fluid pulse from the operation of

the tool washes away the cuttings. Impact the tool washes away the cuttings. Impact

tools operate with as little as 500 psi - 1/4”, at

higher pressures, the tool lifts further and

delivers a harder jolt.


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Impact Tool Operation

• On bottom, bring up press at tool (from 400 to

500 psi), add weight (to about 800 lbs.

• Let conditions of deposit or formation decide

ultimate loading and pressure. ultimate loading and pressure.

• Curves of performance are available.

• Increase rate at the tool to change the impact

rate.


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Impact Tool Operation

• The single direction tool only operates when it sits down and bottoms out on something solid. Normally, it is at full extension.

• The bi-directional tool will run if circulation is sufficient. Can wear out as you run into the well if sufficient. Can wear out as you run into the well if circulation is maintained.

• Tools do not store reverse torque (no tendency to unscrew).

• Reports of operating to 600F.


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Impact Tool Specifics

• Tool string is short.

• Can be equipped for use in H2S or HCl.

• Can operate in parallel with motors.

• Can run on any fluid, gas or water. • Can run on any fluid, gas or water.


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Impact Tool Specifics

• For impact tools, produce cracks, then wash

off debris.

• Penetration rates through barium sulfate

reported to 150 ft/hr. reported to 150 ft/hr.

• Pilot hole followed by cleanup run is best.

• Leave at least 1/8” scale sheath thickness on

pilot?


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Impact Tool Special Points

• May need an accelerator in conjunction with

an impact tool, but only in the upper part of

the hole (to a depth of 200 ft). Weight

influences operationinfluences operation

• Can tell a tool stall by lack of pressure

fluctuation.


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Specifics for Impact Tools

• For barium sulfate cleanouts, use water,

solvents or acids.

• Run life? 80 hrs?

– fatigue loading of CT? (None reported) – fatigue loading of CT? (None reported)

– Some seam splitting on worn strings.


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Deposit Removal

• Jetting

– Water jet

– Abrasive jet - cutting

– Abrasive jet - deposit removal– Abrasive jet - deposit removal

– Fluid/Pressure pulse

• Mechanical (milling and chipping)

– mill and motor

– impact tool


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Side Jetting Nozzle

Backpressure from the annular

fluid column in a well decreases

the effectiveness of the jet since

it holds a back pressure on the

flow.


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Nozzle Energy

• Nozzle energy is dependent on the standoff

distance between the nozzle outlet and the

target face. Nozzle diameter (d) is critical to

impact power, standoff sharply drops impact impact power, standoff sharply drops impact

power.

No loss

for 6 d

80% loss from

7d to 24d


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Solids Transport in Annuli

(Conventional Jetting)• Difficult to unload sand from 7” casing even with 1-

3/4” CT

• Very difficult over 20o deviation and Boycott setting range of 30 to 60o is most difficult.

• Low reservoir pressure and dense particles (bauxite • Low reservoir pressure and dense particles (bauxite and BaSO4) are an added problem.

• Example Well – North Sea – 60o deviation, 9-5/8” casing and 3-1/2” tailpipe, very low pressure well –how to unload several meters of fill????


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Typical fluid density increase with sand at 1

lb/gal is about 9%. Sand is 6% of coil volume

at 1 lb/gal.

At 10,000 ft, weight difference between 0.43

and 0.47 psi/ft (1 lb sand) is 0.77 lb/gal or

extra 500 lb


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Jetting Fluids

Filtered Fluid Type Remeadation

brines salt, silt fill

foams heavier fill/large annulus

xylene, toluenexylene, toluene OBM, asphaltene, wax

kerosene, #1 diesel some waxes

acids carb. scales, rust


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Water Blast and Abrasive Targets

• mud debris

• pipe dope

• scale (softer scales for water blast)

• cement residue• cement residue

• mill scale (81 lb/1000 ft?)

• corrosion by-products

• bacteria colonies


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Layers of calcium carbonate scale from surface pipe prior to first stage Layers of calcium carbonate scale from surface pipe prior to first stage

separator. North Sea Field. Subsequent inhibitor treating has

significantly reduced the scale deposition.


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Slot 8, A19 Cumulative Milled Scale

60

80

100

Kil

og

ram

mes p

er

join

t

1200

1400

1600

1800

2000

2200C

um

ula

tive K

ilo

gra

mm

es Kg's per Joint Cumulative Kg's

0

20

40

0 807 1585 2359 3137 3909 4729 5476 6281 7049 7821 8597 9367 10137 10907 11678 12444 13211 13984

Measured Depth ft

Kil

og

ram

mes p

er

join

t

0

200

400

600

800

1000

Cu

mu

lati

ve K

ilo

gra

mm

es


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S19/A14 Cumulative Milled Scale

400

500

600

700

800

Scale

per

jt

8000

10000

12000

14000

Scale Kg's /jt Accumul Milled Scale

Miller scale milling – 12,047 ft to

14,483 ft

0

100

200

300

12047 12140 12233 12328 12419 12512 12606 12699 12792 12886 12979 13073 13166 13260 13354 13448 13542 13636 13730 13824 13919 14012 14106 14201 14295 14388 14483

Measured Depth ft

Scale

per

jt

0

2000

4000

6000


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A12 Cumulative Milled Scale

10000

12000

14000

Scale recovered at the surface – the quantity of scale that arrives in slugs indicates either non

standard hole cleaning rate or material unloading problems.

0

2000

4000

6000

8000

10000

Measured Depth ft

Kg

's S

ca

le


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Cyclone separation of returned BaSO4

scale from a milling operation in Miller

Field.


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Bauxite Cleanouts

• Caution against flowing Bauxite through permanent facilities. Surface pipe, valves and chokes have the most danger of erosion.

• Equipment? - redundant chokes, (over designed manifold), long radius ells, SSSV, and continuous monitoring of all elbows (measured some wall loss monitoring of all elbows (measured some wall loss during the job) - flowed it directly to a flare pit.

• Done safely, but was all special equipment designed for flowback, not permanent facilities.

• High rate gas wells and bauxite always deserve extra caution and conservatism.

Donn Schmohr – 10/20028/25/2015 27George E. King Engineering

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Entering a Well With CT While

Flowing• Scale milling with 1-3/4” CT (tapered

string) on Bruce in the North Sea

• Had to flow a gas well hard, at 60 MMSCFD/1000 BOPD, to get the WHP MMSCFD/1000 BOPD, to get the WHP from a shut-in value of 4000 psi down to 2000 psi, to be able to RIH.

• Could not bullhead water – well is a severe hydrate producer.


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Entering a Well With CT While

Flowing• Concerned about the prospect of running

through the tree (5-1/8" bore), the tubing (4.687"), and the safety valve (4.562"), and QN nipple (4.475") with a 4.4" Turbomill bit. Calculated and confirmed little pressure drop Calculated and confirmed little pressure drop across the bit from the flow rate

• It all worked just fine. And to think we normally pinch wells back/shut them in to RIH, worried about the flow. Never saw any weight loss when we left the riser.

• Source – Charlie Michel, BP, Aberdeen Office, March 2001


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Depth Control With CT

• Problems

– Depth Measurement

• stretch

• temperature

• drag• drag

– Depth Correlation

• CCL, GR not available unless CT is wired

– Alternatives

• tag a known depth

• memory CCL & GR - after the fact check?


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What’s Different in Acidizing with

Coiled Tubing?

• Volume differences between CT and regular

tubing.

• Ability to easily move tubing while injecting

acidsacids

• Easily moveable inflatables for isolation


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Completion Fluid - Checklist

• Is the formation liquid sensitive to liquid relative permeability effects?

• Compatability with formation? (clay and minerals)

• Compatability with formation fluid? (emulsion, sludge, foam, froth)

• Tanks and surface equipment clean?(pumps, lines, hoses, blenders)

• Are polymers breakable? How is breaker added?

• Polymers, hydrated, sheared and filtered? Filter level? Beta rating?

• Minimize the pipe dope?

• Corrosion reactions understood?

• Erosion potential understood?


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Wellbore cleanout

• Common problems (BUT, look at “why” first)

– mud/cement/perf/complet. fluid particles

– scale (acid sometimes)

– paraffin (forget the acid)– paraffin (forget the acid)

– emulsions (acid???)

– sludges (a real thick emulsion, acids worsen)

– tars (no acid here either)


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Internal Capacities of CT

• 1.25 x 0.095” 1.09 bbl/1000 ft

• 1.50 x 0.109” 1.6 bbl/1000 ft

• 1.75 x 0.125” 2.2 bbl/1000 ft

• 2 x 0.134” 2.9 bbl/1000 ft• 2 x 0.134” 2.9 bbl/1000 ft

• 2.375 x 0.134”4.3 bbl/1000 ft

• 2.875 x 0.134”6.6 bbl/1000 ft

Remember that the entire string of CT is “active” in the acid job - not just the depth of the well.


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Problems with Solvents

• rubber/elastomer seal deterioration

• density problems (hard to get to and hold on

bottom)

• getting reasonably pure solvents• getting reasonably pure solvents

– ie., xylene b.p. is 138-144 C

– naphta not nearly as good

– just what is a xylene bottom? - don’t use it.


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Solvent Volumes

• paraffin removal

– 10 to 15 gal/ft of affected zone.

• asphaltene removal

– 10 to 25 gal/ft - and this won’t dissolve much!– 10 to 25 gal/ft - and this won’t dissolve much!

– 100 grams of xylene dissolves 9 grams of

asphaltenes

• tar removal - ? Get a sample.


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Energy in Jetting

• Impact force from pressure drop

• Impact force improved by shaped nozzle

• Cavitation is most helpful, but disappears with

increasing back pressure.increasing back pressure.


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Nozzle Energy

• Nozzle energy is dependent upon the standoff

distance between the nozzle outlet and the

face of the target.

Energy


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Nozzle Power Drop Off

• For the first six to seven nozzle diameters, there is essentially no loss of velocity in the center line of the fluid stream. From seven to 24 nozzle diameters, an exponential loss of up to 80% of the initial velocity, and at clearances to 80% of the initial velocity, and at clearances over 24 nozzle diameters, a more gradual decrease of the remaining energy is seen.

• Typical nozzle is 1/32” (0.8 mm) to 1/8” 3 mm


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Nozzle Efficiency

• The transfer of momentum between a fluid

and a rock surface is relatively inefficient.

Cutting generally only occurs when the force

from the fluid impingement momentum is at from the fluid impingement momentum is at

least 1.5 times the compressive strength of

the rock.

• Typical compressive strengths = 5,000 psi to

12,000 psi.


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Solids

• An improvement over the cavitating nozzle

may be the addition of small solid particles to

form a particle jet.

• The cutting ability of particle jets do not fall • The cutting ability of particle jets do not fall

off as rapidly as cavitating nozzles. They are

still affected by ambient pressure, but not to

the extent of a cavitating nozzle.


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Particle Nozzles

• Particle jet nozzles are typically on the order

of 1/16 to 1/8 in. Erosion of the nozzle is

common and erosion increases with hardness

and concentration of the solids in the stream and concentration of the solids in the stream

at any set of operating conditions.


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Abrasives in Jetting

• Can remove any deposit, including steel.

• Need an abrasive that is just harder than

deposit but softer than steel.

• Even soft abrasives can go through steel if the • Even soft abrasives can go through steel if the

CT movement stalls out.


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Jetting

• Water: May remove softest deposits such as

paraffin, uncured cement and loose rust scale.

• Abrasives: Can remove any deposit but may

cut the pipe.cut the pipe.


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CT Fishing and Jetting Operations – Coiled Tubing

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