Acid Diverting

Acid Diverting

• Best use is usually damage removal in the connection from the reservoir to the wellbore.

• Limits

– Acids follow the path of least resistance – go down the high permeability zones.

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Deeper Acidizing and Alternatives

• Spot acids and chemicals with coiled tubing to eliminate much of the contamination of flowing reactive fluids down the production tubing.

• Diverting is still necessary, however, since acid will more easily enter and go down the path of least resistance, i.e., the highest permeability channels.


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Placement Techniques

• If the acid or solvent doesn’t reach the damage, the job will not work.

• Coiled Tubing is very useful to spot acid in the vicinity of suspected damage but further diverting is needed.

• Diverters may be useful, but must be removable.


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Acid Penetration Distance

• in wide fractures: 25 to 100 ft

• in narrow fractures: 5 to 20 ft

• in matrix: a few inches?

This assumes even reaction – and the most acid will enter (and react) in the wider fractures.

Acid penetration distance along a fracture is limited more by leakoff than by spending rate.

Acid penetration in the matrix will follow the permeability channels.


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Second Acid Penetration Control - Leakoff

• Leakoff is required to get acid to flow into the zone. Without it there is no reaction.

• Sealing off the entry point from the wellbore is the first step to route acid towards another part of the pay zone.

• Continued diverting is necessary with acidizing since by reacting with the flow path, acid increases the rate of leakoff, making injection into other zones much less likely.


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How do you treat the other

zones? => Make the high

permeability zones harder to

enter or the low perm zones

easier to enter.

?

Without any modification of the flow path, where will most of the acid go? => Along the path of least resistance.

Permeability variance – the source of the problems?


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By preferentially reducing the

permeability of the high perm

zones, there is a chance to

force acid into the lower perm

zones. When the block is

effective, the injection pressure

will rise and/or the injection

rate will drop.

Remember! The

blockage must be

temporary unless the

high perm zones have

watered out.

Most diverting agents still

allow some flow through

their “barriers”.

How Diverters Work


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Common Methods of Acid Diversion

• Ball Sealers

• Straddle packers

• Packer and Plug

• Rate diversion

• Foam

• Larger particulates

• Micron sized particulates

• Gels

• Resin or wax beads and dispersions

• Sand backs

• Inflatables


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Methods of diversion and their limitations: Ball Sealers

• Ball sealers are a ball just larger than the largest perforations, that is pumped with the acid or in a diverter stage. The intent is to plug the holes taking the most fluid and divert acid to other perforations.

• After seating on a perforation, the ball is held in place by differential pressure until the pressure is released (equalized) at the end of the job.

• Balls may have densities of 0.9 to 1.3 g/cc, and may float (buoyant), be suspended (neutral density) or sink (high density) in the carrier fluid.

• Some ball are degradable, while most others either sink after the job or flow back with the recovered fluids.

• It takes only 1/20th of a BPM to attract and seat a neutral density ball sealer.

• Too many perforations may cause the rate to be spread out until the balls will not work properly.


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Ball Sealers - Continued • Neutral density ball sealers (1.05 to 1.1 g/cc) are

most effectively used for routine acid injection, while buoyant balls are used for interface jobs or where EOT (end of tubing) is below the perfs.

• Degradeable balls may take days to weeks to completely disappear – depends on fluids and temp.

• Best Practice for ball sealers: – Only used where cement sheath is an effective barrier

along wellbore. – Most effective at perf densities of 4 shots per foot or

less. – Are usually dropped in stages (often 1/3rd of batch at

once). – Pressure is held during the entire job. – Use balls that will stay with the acid in the wellbore.

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Straddle Packers

• Cup or inflatable upper and lower elements with a perforated tube in-between.

• Isolate off a section of perforations and allow controlled injection.

• Limited by straddle length, reset capability, and an effective barrier formed by the cement sheath.

• Common with coiled tubing. Packer length controlled by lubricator length and number of necessary re-sets.


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Rate Diversion

• Diverting fluid by the resistance created by flow through a perforation entry hole (above frac pressure) or perforation tunnel flow capacity (below frac pressure). The more perfs that are open, the more difficult rate diversion becomes unless the permeability is low and the formation, not the perfs, is the control.

• Fluid pump pressure and flow rate and well as well equipment pressure tests are needed.

• Effectiveness is limited by cement sheath in CCP completion. Can be used in open hole.


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Foam

• Gas-in-water emulsion, depends on higher viscosity created by high gas content (see plot).

• Minimum cleanup problems. Best use in formations with formation permeabilities below about 100 md and above 1 md.

• Gas leaks off too quickly in high permeability formations (>100 md matrix or in natural fractures.

• Sometimes more difficult to see pressure rise effect with foams.


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Increasing internal fraction of the “emulsion”

52% 74% 96%

Viscosity

Widely

Dispersed Contact

Deformation

Inverted

Changes in Fluid Viscosity with Change in Internal

Phase of Dispersed or Emulsified Flow


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Larger Particulates

• Work by filling the perforation tunnels and open hole entry points. Much the same manner as building a filter cake by liquid leakoff and particulate dehydration at the face.

• Only works in the higher permeability and some small natural fractures. • In low permeability formations, the larger particles have too much

permeability to be an effective diverter. • Must be removable to re-achieve a good connection to the reservoir.


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Larger Particulates

• Rock salt, benzoic acid flakes, naphthalene flakes, etc. are most common.

• Typical perms of packs of the large particles runs from 300 to 800 md, so diverting is poor.


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Micron Particulates

• Dispersion of materials that can bridge on the formation leakoff sites.

• Many of these materials are not degradable

• Fluid loss control is good in matrix losses, but poor in wide (>0.05”) natural fractures.

• Carried as a dispersion in part of the acid or in a carrier fluid as a spacer.


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Smaller particulates

• Sized salt and carbonate blends designed to bridge off and divert fluid from high permeability zones.

• Very fast acting. Low spurt and leakoff. Very common for brine loss control. Only salt used to divert acid. (low solubility in acids).

• Stability issues with salt – must allow for changes in solubility with temperature and fluid in contact with the cake.

• Removal issues with carbonate – only soluble in acids – weak HCl acid (5 to 10%) suggested.


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Gels

• Both polymer gels and surfactant gels used to divert acid.

• Surfactant (viscoelastic) gels are common with acids and are preferred to polymers. These gels are broken by oil in most cases.

• Polymer gels are a hazard. Most gels broken too quickly and not completely. Polyacrylamide (AMPS, Co-polymer, etc.) are not broken by acids. Higher viscosity makes them harder to recover.


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Organic Resin Slurries

• Organic resin slurries of 10 to 70 micron fines, carried at a few gallons per 1000 gal of acid or a spacer.

• Very effective on matrix losses. Not effective in even the smallest natural fractures or large vugs.

• Most are oil soluble or soften sufficiently at a set temperature to allow dispersion.

• Insoluble in water – not used in injectors unless a solvent flush follows the acid.


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Wax Beads

• Follow the general diverting method of the resins.

• Selection may depend on melting range or oil softening range.

• The size of the beads is set by ability to plug but wax beads also deform, creating an excellent seal. Their low density makes it easier to carry them in stimulation fluids in comparison to heavier diverter materials.

• Sometimes useful to use a solvent over-flush at the end of the job to remove wax or resin


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Acid Diverting

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