Acidizing products and additives

Acidizing removes near-wellbore formation damage by dissolving or bypassing drilling mud, completion fluid or other restrictions. These treatments include matrix pump rate jobs, washes and chemical injection. Matrix stimulation techniques are performed without fracturing reservoir rock. Acid is used to remove drilling, completion, workover or production damage. Solvents and surfactants like crude, condensate, diesel or mutual solvents are used to change pore fluid or formation wettability characteristics. Washes remove scale and other dispersible or soluble material from formations, perforations and casing.

Formation Damage

The purpose of the above methods is to improve well productivity by removing or mitigating formation damage. Hydrofluoric (HF) acid dissolves clay and fine particles in sandstones. Hydrochloric (HCl) acid etches wormholes that bypass damage in carbonates.

   Clay and fines with high surface area and small grains can block or restrict flow through formations. Drilling mud solids like bentonite, barite and drilled solids can penetrate formations. In situ clays may migrate or swell in the presence of fresh water, brines of varying salinity or incompatible fluids.

   Perforation plugging results from zone compaction, gun junk, drilling or completion fluid solids in perf tunnels and precipitation of soluble inorganic salts or mineral scales (calcium carbonate, CaCO₄) as a result of pressure or temperature drops. This damage can often be removed by an acid or chemical wash and requires only small acid volumes.

   Emulsions have internal or discontinuous, and external or continuous phases that form when acid mixes with crude oil, surfactants are misapplied or oil-base mud mixes with formation water. Fines released during acidizing stabilize emulsion droplets. Mutual solvents added to treatment afterflushes help prevent emulsification and break stabilized emulsions. Proper design and use of spacers can separate produced formation fluids from acid and prevent formation of emulsions and sludges.

   Relative permeability and wettability can interfere with fluid flow in pore spaces. Improper surfactant use can change formation rock surface wettability from water- to oil-wet and restrict oil output. Special solvents or surfactants can restore water-wet conditions.

   Asphaltene and paraffins from organic materials that precipitate from some crudes when pressure or temperature drops during production can build up and block near wellbore formation, perforations and tubulars. Deposits can be removed mechanically with scrapers or with organic solvents, and hot oil or water.

How To Use This Reference

Products are subdivided into groups that have similar function and performance. Where applicable, groups have been subdivided to reflect significant differences in additive chemical nature to emphasize uniqueness in the product lines of each company. What cannot be reflected are differences in performance resulting from different sources of materials, and from fluid and formation compatibility effects. Users are cautioned that it is generally not possible or prudent to make direct "translations" of acid or stimulation treatment fluid formulations between service companies based solely on additive descriptions.

Products and additives are grouped into 28 categories:

		Water-Base Completion Fluids			Foamers
		Water-Base Polymers			Scale Inhibitors
		Friction Reducers			Iron (Fe) Control
		Fluid Loss			Oxygen Scavenger
		Diverting Agents			Mutual Solvents
		Polymer Plugs			Corrosion Inhibitors
		Acid Inhibitors			Paraffin Control
		Acid Retarders			Miscellaneous Products
		Emulsifiers			Acid Systems
		Clay Stabilizers			Retarded Acid System
		Surfactants			Mud Acid Plus Surfactants
		Non-Emulsifiers			Mud Acid Plus Alcohol
		Fines Suspender			SGMA
		Anti-Sludge Agent			Retarded HF

   Corrosion inhibitors protect tubulars and downhole equipment from acid attack. They are typically organic compounds that adsorb onto metal surfaces. Inhibitors are chosen based on exposure time and temperature.

   Iron sequestering agents have increased in use and acceptance for handling insoluble iron hydroxide that can precipitate as acids spend in formations. Chlorite clays are a common iron source. These additives are not recommended for carbonates because of incompatibility.

   Mutual solvents are usually included in afterflush volumes to aid cleanup, prevent acid and produced crude oil emulsions, and maintain water-wet conditions. Ethylene glycol monobutylether (EGMBE) is one of the most common and effective mutual solvents for this purpose.

   Other additives include non-emulsifying, anti-sludge and surface tension reducing surfactants. These are designed to address specific formation acidizing requirements and should be used where there is a demonstrated need.

Some additives are unique to specific companies and many products are protected by patents or other legal means. They may be chemically similar, but not identical, and provide similar performance in stimulation treatment formulations. Exact equivalency is not implied, so supplier materials should be tested according to accepted procedures to ensure that performance requirements are met. Lab or field compatibility testing, and prudent job site quality control are recommended in every case.