Acid stimulation

Visualization of warmholes formed in carbonates as a result of acid stimulation.

Acid stimulation refers to using a stimulation fluid containing reactive acids to increase permeability both in production and injector wells, carbonate or sandstone, by dissolving various acid-soluble solids naturally present in the rock matrix or as formation damage.

Stimulation by acidizing is an old production enhancement technique dating as far back as the nineteenth century when Herman Frasch of Standard Oil patented the use of hydrochloric acid (HCl) to stimulate carbonate formations.

Introduction

Acid stimulation needs to be carried out with a full knowledge of the history of the well to determine the best course of action since there have been many cases of acid stimulation causing temporary or permanent formation damage, including turning oil-producing wells into 100% water producers, which is probably due to the complex, heterogeneous nature of formation minerals and the unpredictability of their response to conventional oilfield acid formulations.

There are two basic methods of using acids to stimulate production:

• Fracture acid stimulation
• Matrix acid stimulation

Fracture acid stimulation

Fracture acidizing is to pump the acid treatment above the fracturing pressure of the reservoir rock, which create long, open channels from the wellbore penetrating deep into the formation. Fracture acid stimulation is usually carried out on carbonate reservoirs, which have lower permeability than sandstone reservoirs. It can be used to either remove formation damage or stimulate undamaged formations to produce conductive channels within the fracture where oil and gas can migrate.

A problem with fracture acid stimulation is that much of the acid is used up near the wellbore and is not available for etching the fracture faces farther from the wellbore. In addition, the acid stimulation fluid follows the paths of least resistance and create typically long-branched passageways leading away from the fracture interface, which are called "wormholes". Later injected fracturing fluid tend to leak off into the wormholes rather than lengthening the desired fracture. Leak off control techniques need to be utilized to avoid this.

Matrix acid stimulation

Matrix acid stimulation is pumped into the formation at or below the fracturing pressure. it is useful for stimulating both sandstone and carbonate reservoirs

The objective of matrix acid stimulation in carbonate matrix is to allow the acid to dissolve channels to create wormholes in the near wellbore region, reaching as far as possible into the formation. Carbonate matrix acid stimulation is also useful to treat carbonate cemented sandstones and formation damage from acid soluble species such as calcium carbonate (CaCO₃) or sulfide scales, lost circulation materials, etc.

In sandstone matrix acidizing, the primary purpose is to remove acid-soluble damage in the well and near wellbore area. Treating an undamaged sandstone well with matrix acids does not usually lead stimulation unless the reservoir is naturally fractured.

Acids used in acid stimulation

Acids for carbonate formations

The most common acid used in carbonate fracture or matrix acidizing is hydrochloric acid (HCl). Organic acids such as acetic acid (CH₃COOH) and formic acid (HCOOH) are sometimes used particularly for high temperature applications. Concentration of HCl is typically 15wt%, but can be as high as 28wt% (commercial HCl is usually sold as 37wt% aqueous solution). Lower concentrations can be used as pickling acids to clean up the well in a preflush (to remove scale and rust) or an afterflush.

In high temperature applications, HCl does not produce acceptable stimulation results due to its fast reaction that leads to lack of penetration. Organic acids, like formic or acetic acids, can be used to offer a slower-reacting and thus deeper stimulating acid

Acids for sandstone formations

Sandstone reservoir is mainly composed of quartz and aluminosilicates (such as feldspars). Migration of these particles (fines) into the pores of the near-wellbore area can reduce production and they will not dissolve in strong acids such as hydrochloric acid, but will dissolve in hydrofluoric acid (HF).

Although highly corrosive, HF is classified as a weak acid due to its low ionization in water and it is very toxic. HF, or more usually HF-releasing chemicals such as ammonium bifluoride (NH₄HF₂), is used for sandstone matrix acidizing, combined with hydrochloric (HCl) or organic acids. An aqueous HF/HCl blend is often called a "mud acid". A preflush and overflush of an ammonium salt is often used to remove incompatible ions such as Na⁺, K⁺, and Ca²⁺ that could form insoluble fluorosilicate salts (e.g., Na₂SiF₆) with HF. Generally, the max HF concentration in the fluid package is 3% due to the concern of deconsolidation of near wellbore sandstone formation. HCl/HF ratios usually vary from 4:1 to 9:1.

In sandstone acidizing, one has to be particularly careful of reprecipitation of reaction products, which could cause new formation damage. They occur mostly if the well is shut-in for a long period of time. The basic chemistry is HF reacts first with aluminosilicates to form fluorosilicates, which react further with clays to form insoluble sodium or potassium flurosilicates. Prevention methods include: 1)overflush with dilute HCl or NH₄Cl to push the solution deeper into the formation 2)use delayed acid formulations that generate HF slowly 3) buffered acid system that allow for a deeper penetration. CaF₂ and AlF₃ can also precipitate in the spent acid.

Potential formation damage from acidizing

There are several other ways that acidizing, both for sandstone and carbonate reservoirs, can lead to formation damage if not carried out correctly. These include:

• Loss of near-wellbore compressive strength due to using too much HF either in volume or concentration;
• Formation of emulsion or asphaltic sludge due to incompatibility between the acid and production fluids;
• Water-blocking and wettability alternation damage, which can be repaired with mutual solvent treatments mixed with water or hydrocarbon solvent containing surfactants;
• Fine migration after acidizing - this is fairly common in sandstone acidizing. Bring the well on slowly after treatment can minimize this damage.

For sandstone formation acid stimulation, the resulting permeability improvement peaks at certain acid volume and then drops as the volume increases in oil wells, but is proportional to acid volumes in gas wells. Permeability improvement in gas wells is typically better than oil wells.

Acid stimulation additives

Acid stimulation flush almost always contain:

• Corrosion inhibitor
• Iron control agent - to prevent iron minerals from dropping out
• Water-wetting surfactant - this is needed to remove any oily film from the rock or scale so that the aqueous acid has good contact. A mutual solvent can also be used.

Mange other additives can also be used, such as clay stabilizer, fines fixing agent, antisludging agent, demulsifier, scale inhibitor, H2S scavenger, drag reducer, foaming agent, etc.

Acid placement

Treatment design and planning are often performed to ensure that the acid is placed across the entire interval. The successful acid placement in matrix treatments of open-hole horizontal wells is even more difficult due to the length of zone and potential variation of the formation properties. A successful diversion technique is critical to place the acid to the location where damage exists.

Either mechanical or chemical placement techniques can be used to improve contact of the acid solution with the interval.

Mechanical

Packer systems, ball sealers, or coiled tubing.

Chemical diverters

The diverter is usually applied in a preflush to temporarily plug the zones of highest permeability zones, allowing the main flush to react with other less permeable or more damaged zones. On back production, the diverter is removed from the formation. These diverters include:

• Solid particles that degrade, dissolve, or melt in hot produced water or oil
• Polymer gels
• Foams
• Viscoelastic surfactants (VESs)