acidizing

Acidizing

• Reasons

• Acid Types

• Reactions

• Methods• Methods

• Flow Back

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EFFECT OF FLUID COMPOSITION ON PERMEABILITY

BP/Amoco

Sample 15012 ft.

10

100Liq

uid

Perm

eabili

ty (

md)

Acidizing a core

plug. The

minerals and

physical

constraints in the

core flow path

react to each

fluid flowing

through the core

creating minor

0

1

0 100 200 300 400 500 600 700

Liquid Throughput (PV)

Liq

uid

Perm

eabili

ty (

md)

3% KCl in

Sea Water

5% KCl in

Sea Water

Formation Brine

De-Ionized Water

10% HCl

5% KCl

in Brine


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creating minor

changes. Acid,

however, sharply

increased

permeability in

the core.

Transferring this

type of result to

the formation is

often a problem.

Acids

• Acids used in well stimulation and cleanup

• The purpose of an acid is to remove formation damage or improve initial permeability.

• Secondary and byproduct reaction from • Secondary and byproduct reaction from acidizing must be controlled to prevent potentially damaging precipitation.

• Effective acidizing is different that acid testing in the laboratory. Correct placement of acid is the major concern.


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Acids

• HCl - hydrochloric

• HCl/HF – hydrochloric and hydrofluoric mixture, often called mud acid.

• Acetic – most common use is vinegar (4%)• Acetic – most common use is vinegar (4%)

• Formic – ant and bee sting irritant.

• Others – sulfamic and chloroacetic are the dry acids or stick acids used for spot application of weak acids.


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HCl or Hydrochloric (Muratic) Acid

Hydrogen chloride gas dissolved in water

• Maximum concentration about 36 to 38%, depending on temperature. (Note - There is no such thing as 100% hydrochloric acid.)

• Increasing HCl content lowers solubility to other gases, • Increasing HCl content lowers solubility to other gases, additives and salts.

• Common Concentrations– 5 to 10% washes for scale, pickling, and preflushes

– 10 to 15% for matrix acidizing

– 20 to 28% for fracturing

• One of the most frequent acid problems is using too strong of an

acid.


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HCl acid in Oil Industry

(reasons for concentrations)

• 15% HCl, highest concentration of HCl that earliest inhibitor would work in.

• 28% HCl, highest concentration of HCl that can be hauled in an unlined steel tank (US highway regulation).regulation).

• When designing an acid system, testing on representative deposits and core from the well, consideration of corrosion problems and secondary reactions and stability of dissolved materials is an absolute necessity.


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HCl Acid Byproducts

• Calcium chloride (CaCl2) salt (dissolved)

• CO2 gas

Other common byproducts

• Emulsions• Emulsions

• Solids from nonreactive parts of formation

• Residue from damage deposits

• Fine particles released in the formation, etc.


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Acid Density

Acid Initial Spent

10% HCl 8.75 ppg 9 ppg

15% HCl 8.95 ppg 10 ppg

28% HCl 9.3 ppg 11 ppg28% HCl 9.3 ppg 11 ppg


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Initial and spent acid density values are very rough estimates – the specific solution

density is also affected by dissolved gases, additives such as alcohols and surfactants

from the job, mineral such as iron from corrosion and/or precipitation prior to the

sampling point.

HCl/HF acids

• For use in removing clay and mud damage

• Don’t use it on carbonates (yields a

precipitate, calcium fluoride, CaF2)

• References of HF and various clay reactions:• References of HF and various clay reactions:– Gdanski, R.D.: “Kinetics of the Primary Reaction of HF on Alumino-Silicates”

SPE 66564, SPE Production and Facilities, Vol. 15, No. 4, Nov 2000, p279-287.

– Gdanski, R.D.: “Kinetics of the Secondary Reaction of HF on Alumino-Silicates”

SPE 59094, SPE Production and Facilities, Vol. 14, No. 4, Nov 1999, p260-268.

– Gdanski, R.D.: “Kinetics of the Teritary Reaction of HF on Aluminosilicates” SPE

31076, SPE Production and Facilities, Vol. 13, No. 2, Nov 1998, p75-80.


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HCl/HF concentrations

• 12% HCl / 3% HF - mud removal in wellbore

• 9% HCl / 1% HF - moderate clay content sandstones

• In simple terms, the amount of HCl is increased to • In simple terms, the amount of HCl is increased to

offset the spending on certain minerals such as

aluminum in clays. The HF requires live HCl to

prevent precipitation of HF reaction products.


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Other Acids:

Phosphoric – not recommended in most formations

• precipitates calcium phosphate when it spends on calcium minerals – inhibitors won’t spends on calcium minerals – inhibitors won’t prevent it (inhibitors adsorb).

• low corrosion at high temp, but watch long term contact

• once used with HF, but not generally recommended.


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Other Acids:

Sulfamic: (stick or solid acid)

• Use at BH temps below 150o F – higher

temperature may create sulfuric acid

• OK on light coatings of acid soluble scales• OK on light coatings of acid soluble scales

• very limited dissolving power

• commonly used without an inhibitor


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Other Acids

Chloroacetic: (one of the powdered acids, also

available in stick form)

• very limited reactivity

• low dissolving capacity• low dissolving capacity

• effective at lowering pH and slowly removing

some reactive scales.

• commonly used without an inhibitor


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Other Acids:

Citric:

• iron sequestering agent

• very limited reactivity


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Other Acids:

Acetic

• limited reactivity

• limited iron control – can aggregate the formation of some sludges! Use with a sludge preventer.

• expensive for carbonate amount dissolved• expensive for carbonate amount dissolved

• less corrosive at high temperatures

• maximum concentration used downhole is 10% (by-product solubility problems).

• Note: acetic is often used as the acid of choice at higher temperatures but has very limited reactivity and dissolving capacity (e.g., vinegar is 4% acetic).


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Other Acids:

Formic:

• expensive for amount of carbonate dissolved

(5 times HCl cost on a pound of carbonate

dissolved basis)dissolved basis)

• less corrosion than HCl at high temperature?

• Handling concerns: e.g., Formic is the irritant

in bee and ant stings.


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Acid Mixtures:

Acetic/ HCl

Formic/ HCl

• Advertised as “slower reacting” – but not not so much at higher temperatures

• iron control – pH type control only – watch sludge • iron control – pH type control only – watch sludge development. (Iron reducer control and a anti sludger are more effective at preventing sludges.)

• high temperature uses based on perception of less corrosion – tests are suggested for temperatures over 300F.


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Other Acids

Formic/ HF

• high temperature sandstones – this is a useful

product with few problem areas.

• Though to be less corrosive at higher • Though to be less corrosive at higher

temperatures, but recent work shows that it

still needs inhibitor.


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Sulfuric and Nitric Acids

• Sulfuric acids not used because of insoluble

sulfate by products with calcium. Sulfuric also

reacts with and modifies some oils to sludges.

• Nitric acids not used because of danger of • Nitric acids not used because of danger of

creating byproducts with oil that could raise

an explosion hazard.

• Also, no inhibitors.


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Common Acidizing Problems

• Use of too strong an acid for damage• Use of too much acid• Wrong type of acid• Use of acid at all!• Watch:• Watch:

– temp– reactants– Time

• Acid can be very useful, but live acid has only shallow penetration in most formations and may not react with many forms of damage.


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Acid Reaction Basics

• Controls (Limits) on live HCl acid penetration:

– Matrix treating: area to volume ratio. In the matrix, the area to volume ratio is about 20,000:1 – this means the acid spends quickly if the formation or damage is acid soluble.formation or damage is acid soluble.

– Fracture acidizing – with area-to-volume ratios of about 50:1, acid reaction is slower and the dominant control on penetration distance is leakoff into side pores and channels.


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Acid Reaction, HCl-on- Carbonate

• Reaction type = first order (fast)

This means that acid spends as quickly as the acid

reaches the formation surface and the byproducts reaches the formation surface and the byproducts

are carried away.

Remember, the area-to-volume ratio controls the

surface area presented to HCl acid for reaction. It

also controls how much acid is there to react.


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Area-to-Volume Ratio

• in wide (0.3”) fracture = 50:1

• in narrow (0.01”) fracture = 500:1

• in matrix (10% porosity) = 20,000:1


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Natural Fracture in Limestone


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Remember the surface

area issues – HF acid

reaction with clays can

be very quick.

The entire picture is

about 25 x 20 microns8/24/2015 25

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Acid Reaction, HCl-on-Silica

• very, very slow

More of a tiny solubility of silica in acid than a

reaction. Sand grains are very large compared

to the reactive surface area of clays.to the reactive surface area of clays.

For HF reaction on silica, the rate is second

order and is slower than the reaction of HF on

clays.


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Approximate surface area of clays for

common clay structures – highly variable

Sand Grain 0.000015 m2/g

Kaolinite 22

Smectite 82

Illite 113

Chlorite 60Chlorite 60

The actual surface areas for clay are highly variable and depends on deposit configuration. However, the difference between authogenic clay area (clay in the pore throats) and sand grain area are on the order of 6 to 7 orders of magnitude.


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Secondary Acid Penetration Control

(when not in the matrix) - Leakoff

• Leakoff is required to get acid to flow into the

zone. Without it there is no reaction.

• However! By reacting with the flow path, acid

increases the rate of leakoff, making injection increases the rate of leakoff, making injection

into other zones much less likely.


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Without any modification of the flow path, where will most of the

acid go? => Along the path of least resistance.

How do you treat the other zones? => Make the high permeability

zones harder to enter or the low perm zones easier to enter.

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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.

Most diverting agents still

allow some flow through

their “barriers”.

A typical

Remember! The

blockage must be

temporary unless the

high perm zones have

watered out.


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A typical

formation may

have 2 to 3

orders of

magnitude

permeability

difference

between the

minimum and

maximum

permeabilities.

Leakoff Learnings:

Variable Natural Fracture Widths

Many natural fractures open or open wider as injection pressure is raised

• In these cases permeability can increase by an order of magnitude.order of magnitude.

Natural fractures may close in some cases with unsupported fractures and high closure stresses as reservoir pressure declines

• Total perm including natural fractures can decline to matrix permeability as it closes.


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Acid Penetration Distance

• in wide fractures: 25 to 100+ ft

• in narrow fractures: 5 to perhaps about 20 ft

• in the matrix: a few inches?

• When a few permeability channels are opened by acid in carbonates or sandstones, “wormholes” or tunnels in carbonates or sandstones, “wormholes” or tunnels can develop for short distances (maybe a few feet). Leakoff usually limits their growth.

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

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


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Leakoff Learnings: Wormholes

(uneven reaction)

• starts in a high permeability channel or

fracture

• widens pathway as acid reacts

• holes become “rounder” • holes become “rounder”

• limited by side branches (leakoff)

• Length? – few inches to a few feet. Higher acid

viscosity limits leakoff.


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Gases Used in Acidizing

• Why? – flow back assist (unloading energy)

• Gasses:

– Nitrogen

– Carbon Dioxide, CO2, both added CO2 and CO2– Carbon Dioxide, CO2, both added CO2 and CO2

from the acid reaction.

– And - just a trace of dissolved oxygen (7 parts per billion in 15% HCl) - this is usually not a significant factor in most operations, unless specialty corrosion problems develop. However – chrome 13 pipe may be affected.


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Gas Volumes and Types

High Pressure Gas Wells – no added gas needed?

Low Press Gas Wells – about 100 to 700 scf/bbl

depending on BHP. Check the well unloading

performance and consider adjusting the gas volume. performance and consider adjusting the gas volume.

Type:

– Gas Well - Nitrogen or Carbon Dioxide

– Oil Well (above bubble point) - Carbon Dioxide

– Oil Well (below bubble point) – Nitrogen or Carbon Dioxide


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Gas Considerations

• Nitrogen has less than 10% of the solubility of carbon dioxide in oil.

• Carbon dioxide can enter the “dense phase” in higher pressure wells and can affect fluid density.

• On Backflow• On Backflow– Gas provides lift (is a choke needed for flowback

optimization??

– Gas may create foams or other emulsions. A foam or emulsion breaker is often used in the overflush to control problems (foam, precipitates and treaterupsets on the backflow.


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References on Facility Upsets Caused

by Acidizing

• Gidley, J.L., Hanson, H.R>: “Prevention of Central Terminal Upsets Related to Stimulation and Consolidated Treatments,” SPE 4551, 1973.

• Coppel, C.P, Newberg P.L: “Factors Causing Emulsion Upsets in Surface Facilities Following Emulsion Upsets in Surface Facilities Following Acid Stimulation,” SPE 3687 (see also 5154), 1972.

• Durham, D.K., Ali, S.A., Stone, P.J.: “Causes and Solutions to Surface Facility Upsets Following Acid Stimulation in the Gulf of Mexico,” SPE 29528, 1997.

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Putting Acid To Work

• Identify the damage and match an acid or

solvent to remove it.

• Find a way to get the treatment to the

damage.damage.

• Find a way to remove the spent acid and other

fluids and solids.


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Wellbore cleanout

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

– mud/cement/perf/complet. fluid particles

– scale (acid sometimes)– scale (acid sometimes)

– paraffin (forget the acid)

– emulsions (acid???)

– sludges (a real thick emulsion, acids worsen the problems)

– tars (no acid use here either)


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Perforation Damage

• debris from perforating• sand in perf tunnel - mixing?• mud particles• particles in injected fluids• pressure drop induced deposits• pressure drop induced deposits

– scales– asphaltenes– Paraffins

• Much of the perforation damage may be removed by breaking down the perfs with water – no acid needed.


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Cement

• Crushed cement particles can be removed quickly by HCl, but larger surface area deposits form a calcium alumino silicate coating of variable composition over the initial reaction site and the reaction stops. Jetting acid against cement does not allow the coating to form and the reaction proceeds quickly.

• Cement can be acidized by HCl/HF mixtures.• Cement can be acidized by HCl/HF mixtures.

• When channels are opened to water following an acid job, it is most likely that the acid opened an existing channel in the cement that was formerly filled by drilling mud.

• Perforating effects on cement are thought to be minor unless the cement was in poor shape before perforating. Hundreds of perforating tests at surface shows that perforating penetrates but rarely shatters cement when the target is confined.



Near Well Damage

• in-depth plugging by injected particles

• migrating fines

• water swellable clays

• water blocks, water sat. re-establishment

• polymer damage• polymer damage

• wetting by surfactants

• relative permeability problems

• matrix structure collapse

Watch the injection pressure response of acid when it reaches the formation – a very fast drop in pressure at a constant rate indicates very shallow, acid soluble damage.


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Clays?

• Opinion - Most problems blamed on clays are not clay damage.

• Only smectite is routinely swellable to water. Some forms may also disperse particles.

• A few forms of kaolinite may disperse in water flows but may be more sensitive to fluid velocity than fluid type.may be more sensitive to fluid velocity than fluid type.

• Unstable, free-standing chlorite “rims” around sand grains that have been dissolved are known in the US Gulf Coast. This is rare. The sensitivity is mostly to fluid flow but do have some acid reactivity.

• A form of water sensitive illite has been reported in the North Sea – this is also rare.



Waterblocks

• A relative permeability effect made worse by low pressure and poor displacement.

– Most likely problem areas:

• Gas wells

• Low pressure reservoir – Pressure <<0.3 psi/ft• Low pressure reservoir – Pressure <<0.3 psi/ft

• Moderate to low permeability and small pore throats,

• Untreated water

• Acid may not help – need to reduce the water surface and interfacial tension and re-establish gas saturation. Inject non-adsorbing surfactant or alcohol (watch the asphaltenes) and overflush with Nitrogen or CO2 gas. May require multiple treatments.



Clay Reactions with Acid

• See Gdanksi’s papers on HF reactions on clays

and minerals. Composition, form and location

are very important.

• Clay may not be completely removed by the • Clay may not be completely removed by the

quantity of acid available at the reaction site

and particles can be liberated from the matrix

in some cases.



Polymer Removal

• From: muds, pills, frac, carriers

• Stability of polymer? - for years in some cases.

• Removal methods: – time at temperature, 1 week w/ breakers, but breakers

often separate from polymer during job.often separate from polymer during job.

– acid, small volume, 10% HCl, as a soak, but reaching damage is difficult because it is difficult to get acid to flow into a damaged (low perm) area.

– bleach (3% to 5%) - 5 to 15 gal/ft, soak, bleach is corrosive; has problems getting live bleach to damage.

– enzymes and bacteria - soaks, temp critical – good potential if placed correctly.


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Scale Removal

• CaCO3 - HCl wash, however, for extremely thick CaCO3 scales, it may be faster to remove the deposits by milling.

• CaSO4 - dissolver/converter – flush the dissolver/converter out of the well, then acid dissolver/converter out of the well, then acid soak.

• BaSO4 - some dissolvers may work on scale mixtures, but nearly pure BaSO4 at pressure is only very slowly reactive to common dissolvers. Consider mechanical removal.

• FeS2 - good luck! - mechanical best option


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Sludges?

• asphaltenes and irons are triggers for formation of a sludge.

– 500 ppm iron (or more)

– 0.5% asphaltenes (or more)

• can be almost rigid when stabilized by high • can be almost rigid when stabilized by high concentrations of silt.

• don’t need much energy to form.....

• Very, very hard to break – difficult to disperse solvents into highly viscous sludge.

• Treatment – soaks with xylene and/or dispersants. Heat, energy (mixing) and repeat applications help.


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Will an acid job remove the damage?

• Ask some questions:

– What is the damage?

– What are the drawbacks to acid in the well?

– Has it worked in offsets? What is local experience?– Has it worked in offsets? What is local experience?

• Is there another way?

– Solvents?

– Reperforating? (easier to control than acid!)

– Breakdowns with a “safe” brine?



acidizing

Documents

hydrochloric acid

acid testing

acid system

mud acid

highest concentration

acid density values

frequent acid problems

acids acids