Kill and Completion Fluids

Kill and Completion Fluids

• Kill Fluid Objectives

– Quickly limit leakoff to an acceptable level

– Cleans up fast, no interference w/ completion

– Does not permanently damage the rock

– Does not react with other fluids

– Does not cause surface facility upsets

– Economics must be acceptable

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Leakoff Control

• FIRST – what causes leakoff? A pressure differential from the wellbore to the formation across a permeable formation.

• Leakoff rate is an indicator of the quality of the connection between the wellbore and formation.

• Stopping the leakoff may damage the connection.

• Is stopping leakoff absolutely necessary? – What is limit? 10 bbl/hr? Is the limit reasonable?

– Can this well be created live? (snubbing, coiled tubing)

– Can a lighter fluid be used to cut pressure differential?


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Particle Size Distribution

• Quickly controlling leakoff requires a range of particle sizes.

– Coarse particles (fibers & flakes build a framework on large pores, fractures and vugs.

– Medium particles bridge of the large particles, providing a stable second matrix

– Fine particles “seal off” the smallest sites, sharply reducing leakoff possibility.

• Removable particle packs will be on the surface.


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What Particle Causes Damage?

• Particles that invade through the matrix and bridge in pore throats.


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Permeabilit

y md

Mean Pore

Size,

micron

Particle

Size to

Bridge,

micron

Most

Damaging

Particle

Size

Range,

max

Most

Damaging

Particle

Size

Range, min

4000 63 21 9 6

3000 55 18 8 5

2000 45 15 6 4

1000 32 11 5 3

750 27 9 4 2.7

500 22 7 3 2

250 16 5 2 1.6

100 10 3 1.4 1

50 7 2 1 0.7

Particle Damage Index (from Halliburton)


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Sized Salt

• Micron size (20, 50, 6/300 – detm by need)

• Polymer varies depending on base fluid

• Mixed in saturated brine

• Poor QA/QC particle size distribution

• Temp limit < 275oF

• Starch used to aid fluid loss control

• Soluble in unsaturated treating fluids


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Sized Calcium Carbonate System

• Sizes: 5,25,50,150, 600, 2300 micron

• Polymer depends on base fluid

• Can be mixed in any base fluid

• Controlled particle size distribution (PSD)

• PSD minimizes invasion into formation

• Temp limit of polymer

• Soluble in hydrochloric acid


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Main Goals

1. Limit damage

2. Control the fluid loss

3. Get the well to clean up rapidly


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Achieving the Goals

• Base fluid – Non damaging to the formation

• Look at clay and mineral swelling and dispersion potential

• Will clays and minerals trap and hold liquids?

• Typical load fluid recovery for formation? Time dependent?

– Non reactive with formation fluids • Emulsions, sludges, asphaltenes, etc

• Scales – CaCO3, CaSO4 are most common

– Stable at formation temp for duration of job • Most polymers good only to 275oF

• Watch solubility of fine particulate additives

– Particles in the base fluid – filtering needed?

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Monovalent Fluids

• Sodium chloride

• Sodium bromide

• Sodium formate

• Potassium chloride

• Potassium bromide

• Potassium formate

• Cessium formate


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Divalent Fluids

• Calcium chloride

• Zinc bromide

• Calcium bromide


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% change in PI

-100

-80

-60

-40

-20

0

20

40

60

0 2000 4000 6000 8000 10000 12000

Total Fluid Loss, bbls

% c

han

ge i

n P

I o

n W

ork

over

SPE 26042

Change in PI vs. fluid loss – Alaska Wells Note that the loss of even large volumes of sea water fluid was not, in itself, detrimental.

A strong correlation was seen between damage and operations involving milling and scraping in the perforated interval.


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Filtration

• Filtration removes unwanted solids from kill,

completion or stimulation fluids to prevent build

up of solids and sludges in the well and to make

sure any fluid that is lost does not plug the

formation due to particles.

• Two basic filtration systems:

– cartridges (nominal or absolute)

– filter presses (Plate and Frame or Pressure Leaf)


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Risks and Issues

• Filtration can impact the injection rate.

• Filtration may be an unnecessary cost in some

hard rock wells with very small pore size and low

conductivity requirements.

• Filtration is an absolute necessity in gravel

packing – conductivity of the pack in these jobs is critical.


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Risks and Issues

• Filter presses use beds of diatomaceous earth (DE) or

perlite,

– they have the advantage of high solids tolerance and throughput,

units are large but cheap to operate.

– Cartridges should be used where small low volumes of relatively

clean material have to be processed. They have smaller

throughputs than and less tolerance to dirty fluids. Cartridges are typically more expensive

• There may be HSE risks associated with operating and

disposing of filtration medium (dust, chemical residue, etc.).


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Learnings

• Single stage cartridges not appropriate for very dirty or some viscosified fluids

• DE presses present HSE issues.

• Tendency is to over specify filtration specs.

• Do not filter oil with DE.

• If underbalanced perforation is planned, is filtration required?

• Filter kill pills? (solids range more important).

• Absolute cartridges are 2 to 5 x Nominal cost


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Best Practices

• For general applications, coarse filtration to 80

microns is all that should be considered when fluids do not penetrate the formation

• When a fluid penetrates the formation filtration is

more likely to be required, it should be tailored to

the pore throat size of the formation.

– A simple guide to setting a specification is 14% (1/7th) of the average pore throat diameter


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Best Practices

• Filtration below 2 microns is usually impractical in well operations

• Always use a guard filter downstream of a DE press

• For a DE press filtration rate is approximately 1 bpm per 100 sqft for sea water and 0.5 bpm per 100 sqft for a brine


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How Clean?

• The determination of how clean the well is usually based on the cleanliness of fluids returning from the wellbore.

• The most common measures are normal turbidity units (NTU) and solids content, neither relate to what is left in the well.

• Also: – junk baskets, gauge rings and recovery systems give some

indication of solids removal.

– torque and drag (related to the friction coefficient of fluid coating the casing walls) and

– cleanliness of the clean up string when pulled.


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Kill Fluids: Typical Ingredients

• Polymer – 1 to 3 lb/bbl

• Buffer – varies with fluid

• Breaker (48 hrs) – varies with the BHT

• Fluid Loss Additive

• Clay Stabilizers – (watch this one – they are lost to adsorption)


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Polymer selection drives base fluid selection

• Monovalent => XC polymer,

• Divalent => HEC polymer


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Polymer Breaker

• Enzymes (internal)

• Oxidizers (internal)

• Acids (external)

• Keeping a breaker with the polymer is very difficult – they are often separated by dehydration.


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Polymer Pills

• Often very successful at controlling fluid losses.

• The formation damage and problems polymer pills create are a function of how well they are selected for the application. – Don’t let them invade (skins > 100 if invade)

– Watch the temperature

– Have multiple methods of breaking polymers

– Expect damage

– Don’t use if another (less damaging) method is available. Mechanical?


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Polymer Damage

• Damage is temperature, time and formation dependent.

• Temps over 200oF are OK for low polymer fluids but may caramelize heavy polymer loads

• Just like particles – polymer should not invade the formation.

• Breaker schedules are critical. Acids work only on some polymers and only if the acid can contact the polymer.


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K-Max

• Potassium, sodium and calcium brines

• LGC – 15 lbs/6 gal pail

• Requires service company personnel

• Base fluid up to 14 ppg (no zinc)

• Temp Range 75 to 300oF

• Crosslink is pH controlled and reversible

• 98% regained perm with HCl


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Z-Max

• Zinc brines

• LGC 15lbs/6 gal pail

• Requires service company personnel

• Pilot testing before mixing

• Temp range 75 – 220oF



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Max-Seal

• Crosslinked gel


• Base fluid – NaCl, KCl, CaCl2

• Temp range 75 to 275 F

• Liquid gel concentrate

• Service company personnel not required

• Contains no internal breaker

• 98% regained perm with HCl


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Workover Effects on Surface Facilities

• Impact of completions, workovers and stimulation fluids on facility operations

• Flow back solutions


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emulsion

water

oil

dump valve

dump valve

clean oil

The primary problem with backflowed kill fluids are solids, polymers and low pH that create severe emulsions.

Emulsions require more time to break and will curtail or stop well production.

3 phase separator


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Causes of Treating Upsets

• Change in pH of in-coming fluid

• Increased flow overwhelming separators

• Formation solids

• Paraffin and asphaltenes

• Completion fluids and additives

• Corrosion solids (soluble iron maximums)

• Polymers, acids, caustics, etc.


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Biozan Pills

• During coiled tubing cleanouts and

underreaming jobs, Biozan or other gel

pills are utilised as high viscous sweeps.

• While they work great downhole, they can

create facility upsets since the returns are

laden with emulsion-forming solids and

polymer.


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Biozan Pills

• Miller and Magnus field personnel have found that 30 ppm of Antifoam (as a fraction of the water phase flowing to the separator) injected upstream of the separator solves oil-in-water carryover problems.

• It was very clear from the Miller experiences the outcome both with and without antifoam. Antifoam has been found superior to hot water dilution or sodium hypochlorite injection.

Source – Charlie Michel, Aberdeen 8/25/2015 32


Biozan Facility Upset

• The 20 bbl (1.75 ppb) Biozan pill was circulated

around the coil at 2bbl/min with scale-inhibited

seawater.

• Used Anti-foam at 30 ppm injected into the flow

line between xmas tree and test separator at 4

gal/min (1.5 litres/hour) for approximately 3

hours; antifoam was started about 40 minutes

before Biozan pill arrived.


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Kill Fluids After Perforating

• Extreme Overbalanced or Underbalanced perforating may be very beneficial, but what happens after you kill the well and pull the gun?

• Depends upon the kill fluid/pill formulation

– Range is: no damage to severe damage


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Anschutz Ranch Case Histories

• 12,000+ ft deep, gas condensate, Nugget sandstone with 5 to 20 md perm. No Clay.

• Filtered, 2% KCl fluids as kill fluids provided no damage as evidenced by pre and post kill buildups.


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SKIN FACTOR

PRE-KILLING POST KILLING

Cusiana 2A-ST 10 90

Buenos Aires A1 11 122

Buenos Aires B2 32 43

Buenos Aires Y7 17 63

Colombia Data, Shoot and Pull Perforating (This was before pill formulation was reworked.

Note – Colombia rock permeability is dominated by a few large pores that are very easily damaged by solids)

Source - Juan Carlos Rojas and Phil S. Smith 8/25/2015 36


Well Preparation

• Shut-in and equilibrium

• Debris Management –drilling/completion

• Filtration


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Shut-In Timing for Repair or Recompletion

• allow well to come to equilibrium.

– Time?

• High rate wells, single zone, short time shut-in

• Multiple zone or multiple layer – much longer

• Low permeability – much longer

• Gas lift? – 1 to 12 hours

• Problem? – cross flow interferes with acid placement.


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Cross Flow

• Flow from one zone to another

• Can occur with the well dead at surface

• Can produce significant damage in a few cases.

– Scales from water mixtures

– Paraffin and asphaltene precipitation

– Water blocks in low pressure or sensitive zones


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Kill Fluids

• Never use dead crude – asphaltene precip.

• How sensitive is the formation?

• What inhibitors are needed?

• Have all fluids been tested with other fluids and materials?

• Filter all fluids to 2 to 5 micron with a beta rating of 1000.

• Pickle the tubulars before the job?


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Kill and Completion Fluids

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