Drilling fluid additives are the materials, from barite and bentonite to polymers, salts and surfactants, that give a drilling fluid its density, viscosity, filtration control and inhibition, and this reference sorts them into 15 additive classes. More than 90 % of the barite sold in the US goes into drilling fluids, and drilling mud takes 22 % of US bentonite use (USGS Mineral Commodity Summaries 2026, 2025 estimates).
Additives are what turn a base fluid into a working mud. Water, brine, oil or a synthetic base fluid carries them, and the finished drilling fluid is the mixture of base fluid and additives; sold as products, the additives are also called drilling chemicals or mud chemicals. The practical questions are which class does what, and which classes work together in one mud.
The 15 classes fall into seven function groups and interact through pH, calcium and electrical charge, and the fluid system decides which classes a mud uses. Only 13 materials, all in three classes, carry an API Spec 13A grade; every class is dosed by field tests under API RP 13B-1 and 13B-2. Offshore, US rules limit the discharged fluid as a whole, while the PLONOR list names single substances, so offshore status is checked material by material.
Standards and regulations are checked against their issuing bodies, product values against the named data sheet and figures against the dated source named in the sentence; see our methodology and fact-checking.
What Are Drilling Fluid Additives?#
A drilling fluid additive is a material mixed into the base fluid of a drilling fluid, whether water, brine, oil, a synthetic base fluid or foam, to give the fluid one property it needs downhole. A drilling fluid has a liquid continuous phase, a solids discontinuous phase and sometimes a gas phase. Additives sit in each phase: salts and polymers dissolve in the liquid, weighting agents and clays form the solids, and foaming agents hold the gas in foam systems.
Additive classes are named by the task an additive performs, not by its chemistry. One chemical can therefore belong to two classes: lignite thins a water-based mud and also reduces its fluid loss, and six such dual-class materials are listed at the end of this page.
Every additive changes at least one measured property of the mud, such as density, rheology, filtration or chemistry. Mud engineers track these drilling fluid properties on the daily mud report and add the class that moves a property back into its programmed range.
What chemicals are used in drilling mud?#
Drilling mud uses five groups of chemicals: minerals, polymers, salts, alkalis and surfactants. Barite and bentonite are examples of the minerals; polyanionic cellulose, xanthan gum and starch of the polymers; potassium chloride and calcium chloride of the salts; caustic soda, lime and soda ash of the alkalis; and emulsifiers and drilling detergents of the surfactants.
Synthetic polymers such as partially hydrolyzed polyacrylamide (PHPA) and AMPS (2-acrylamido-2-methylpropane sulfonic acid) copolymers, asphaltic materials such as gilsonite and sulfonated asphalt, and the lignosulfonates and lignite complete the organic side. Biocides such as glutaraldehyde, tetrakis(hydroxymethyl)phosphonium sulfate (THPS) and the isothiazolinone blend CMIT/MIT protect the natural polymers from bacteria.
Each of these chemicals is a drilling fluid material with its own grade, function and safety data. The A to Z index of drilling fluid materials lists every one of them with grade, function and safety.
The 15 Drilling Fluid Additive Classes and What Each Does#
Fifteen additive classes cover every material in a drilling fluid, from weighting agents that raise density to surfactants that keep the bit free of sticky solids. The table below compares the 15 classes by what each does, its main materials and the fluid systems that use it.
| # | Class | What it does | Main materials | Fluid systems |
|---|---|---|---|---|
| 1 | Weighting agents | Raise density to hold formation pressure | Barite, hematite, ilmenite, manganese tetroxide, calcium carbonate; cesium formate as a solids-free brine | Water-based, non-aqueous, drill-in |
| 2 | Viscosifiers | Build viscosity and gel structure to lift cuttings and suspend solids | Bentonite, attapulgite, sepiolite, organoclay, mixed metal hydroxide (MMH), xanthan gum, guar gum, hydroxyethyl cellulose (HEC), scleroglucan | Bentonite and polymers in water-based muds; organoclay in oil- and synthetic-based muds; attapulgite and sepiolite in salt water |
| 3 | Fluid-loss additives | Cut the filtrate volume that passes into the formation | Polyanionic cellulose, carboxymethyl cellulose (CMC), starch, lignite, gilsonite, sulfonated asphalt, AMPS copolymers, sulfonated phenolic resin | Celluloses and starches in water-based muds; gilsonite for HTHP fluid loss in oil-based muds |
| 4 | Shale inhibitors | Limit shale hydration, swelling and dispersion | Potassium chloride, PHPA, glycols, polyamines, sodium and potassium silicate, calcium chloride | Inhibitive water-based muds; calcium chloride water phase of non-aqueous muds |
| 5 | Lost circulation materials | Plug the paths through which mud is lost to the formation | Nut shells, resilient graphite, mica, cellulosic and mineral fibers, sized calcium carbonate | Any system, as background treatment, sweeps and pills |
| 6 | Thinners and deflocculants | Lower viscosity or prevent flocculation of clay | Lignosulfonates, tannins (quebracho), lignite, sodium acid pyrophosphate (SAPP) and other polyphosphates, low-molecular-weight polyacrylates | Dispersed water-based muds (lignosulfonate, lime and gyp systems) |
| 7 | Emulsifiers and wetting agents | Form the water-in-oil emulsion and keep solids oil-wet | Calcium fatty-acid soaps (primary), polyamides and imidazolines (secondary), amidoamines | Invert emulsion oil- and synthetic-based muds |
| 8 | Lubricants | Reduce torque and drag between pipe and wellbore | Liquid lubricants, graphite, fine mica | Water-based muds, extended-reach wells, HDD |
| 9 | pH and alkalinity control | Set pH and alkalinity and remove calcium | Caustic soda, caustic potash, lime, soda ash, sodium bicarbonate | Water-based muds; lime in oil-based muds |
| 10 | Biocides | Kill bacteria that degrade natural polymers | Glutaraldehyde, THPS, isothiazolinone (CMIT/MIT) | Water-based muds with starch and natural gums |
| 11 | Corrosion control | Protect steel from oxygen, H2S and corrosive brines | Sodium sulfite and bisulfite oxygen scavengers, zinc carbonate and zinc oxide H2S scavengers, iron oxide (Fe3O4), corrosion inhibitors | Water-based muds; sour wells |
| 12 | Defoamers and foaming agents | Release trapped gas from mud, or make the foam of foam drilling | Octyl alcohol, aluminum stearate, glycols, silicones, sulfonated hydrocarbons; foaming agents | Water-based muds (defoamers); foam and pneumatic systems (foamers) |
| 13 | Flocculants | Bind fine drilled solids so they settle or are removed | High-molecular-weight nonionic polyacrylamide, acrylates, PHPA | Clear-water and low-solids water-based drilling in hard rock |
| 14 | Spotting fluids | Free differentially stuck pipe as a pill placed in the annulus | Oil-based, synthetic emulsion and water-based spotting formulations | A pill inside any system |
| 15 | Surfactants | Clean solids from the bit and hole, raise the rate of penetration (ROP), prevent accretion | Drilling detergents, ROP enhancers, anti-accretion additives | Low-solids water-based muds with fresh or salt make-up water; PDC bits in shale |
Materials listed are examples; each class hub gives the full material table with dose and temperature data and its sources.
Doses and temperature limits belong to products, not to classes, so this overview names materials only and each class hub carries the dose table for its own materials. A dose without the product behind it misleads, because two products of one class can differ in strength and temperature rating.
The first five classes, from weighting agents to lost circulation materials, supply the bulk of the solids and polymers in a mud and set its density, viscosity, filtration and inhibition. Classes 6 to 15 are chemical treatments: they adjust the clay dispersion, emulsion, friction, pH, bacteria, corrosion, gas, fine solids, stuck pipe and bit cleaning of a mud that the first five classes have built.
How Additive Classes Are Grouped by Function#
The 15 additive classes fall into seven function groups: density, rheology and suspension, filtration and sealing, inhibition, chemical control, emulsion and surface control, and pipe movement.
Each group serves one or more of the functions a mud performs in the well. An AADE paper, Deciphering the Daily Mud Report (2015), counts 11 functions of drilling fluid, from removing cuttings and controlling pressure to cooling the bit and minimizing environmental impact.
The seven groups and the classes in each are listed below.
- Density: weighting agents.
- Rheology and suspension: viscosifiers, thinners and deflocculants, flocculants.
- Filtration and sealing: fluid-loss additives, lost circulation materials.
- Inhibition: shale inhibitors.
- Chemical control: pH and alkalinity control, corrosion control, biocides.
- Emulsion and surface control: emulsifiers and wetting agents, defoamers and foaming agents, surfactants.
- Pipe movement: lubricants, spotting fluids.
Groups 1 to 4 are designed into the mud program before the well is drilled, together with the emulsifiers of an oil-based mud, which belong to its base formulation. Groups 5 to 7 are added as treatments when the well calls for them, for example a biocide when bacteria start to degrade starch or a spotting fluid when pipe sticks against the wall.
How Additive Classes Interact in One Mud#
Additive classes depend on each other in one mud: weighting agents need a viscosifier's gel structure to stay suspended, and thinners work in the alkaline range set by caustic soda or lime. Water-based muds run at a pH of 10 to 12 (AADE 2002).
Acidic thinners such as lignosulfonate and lignite are added together with caustic soda for that reason. Without the caustic soda, the thinner itself would pull the pH below the range in which it works.
Calcium treatment depends on where the calcium comes from. Soda ash removes the calcium that gypsum and anhydrite release, while sodium bicarbonate, SAPP or citric acid treat the calcium from cement, because they also lower the pH that cement raises (AADE-15-NTCE-14).
Three combinations work against each other in the same mud and are listed below.
- Mixed metal hydroxide and anionic deflocculants: MMH viscosifiers are incompatible with polyphosphates, lignosulfonate and lignite.
- Ammonium bisulfite and caustic soda or glutaraldehyde: the oxygen scavenger is never mixed with either, and adding it cancels the activity of the biocide.
- Low- and high-molecular-weight polyacrylates: low-molecular-weight grades deflocculate clay, while high-molecular-weight grades flocculate colloids, so the two act against each other.
Oil-based muds tie two classes together through lime. The primary emulsifier is a calcium soap formed from a fatty acid and lime, so lime serves the alkalinity class and the emulsion chemistry at the same time.
Two contaminants show the limits of a single-class treatment. Deflocculants have little or no effect on carbonate contamination, which is treated with lime or gypsum, and a high pH alone is no H2S control, because a small drop in alkalinity releases H2S again (AADE-15-NTCE-14).
Additives by Fluid System: Water-Based, Oil-Based and Pneumatic#
The fluid system decides which additive classes a mud uses: water-based muds draw on every class except emulsifiers and wetting agents, non-aqueous muds rely on emulsifiers, wetting agents and organoclay, and foam systems run on foaming agents.
In a water-based mud, water or salt water is the continuous phase. Clays and polymers build its viscosity, celluloses and starches control its filtration, and thinners, alkalinity agents, shale inhibitors and biocides adjust the chemistry around them.
In a non-aqueous mud, oil or a synthetic material is the continuous phase, as 40 CFR 435.11 defines oil-based and synthetic-based fluids for US offshore discharge. Organoclay viscosifies and gels these fluid systems, and gilsonite controls their high-temperature, high-pressure (HTHP) fluid loss. The emulsified water phase is a calcium chloride brine, with a water activity of about 0.75 at 25 % calcium chloride by mass (AADE 2015).
Foam drilling runs on foaming agents dosed at 1/16 to 2 % by volume of the injection fluid, and 1/2 to 1 % is the typical range (Water Well Journal 2023). Clear-water drilling in hard rock adds flocculants instead, so that fine drilled solids settle out of the water.
Which Additives Have an API Specification?#
API Spec 13A specifies 13 drilling fluid materials, all in three of the 15 classes: weighting agents (barite and hematite), viscosifiers (bentonite, non-treated bentonite, OCMA-grade bentonite, attapulgite, sepiolite and xanthan gum) and fluid-loss additives (CMC-LVT, CMC-HVT, starch, PAC-LV and PAC-HV).
The specification in force is API Spec 13A, 19th edition (2019) with Addendum 1 (2020), Addendum 2 (2022) and Errata 1 (2024), the current edition (API Standards Plan, checked 2026-10-27); a 20th edition is in development. ISO 13500:2008 is the ISO counterpart.
No material of the other 12 classes carries an API 13A grade, among them organoclay, lost circulation materials, PHPA, potassium chloride, lime, caustic soda and lignosulfonate. Buyers of the 13 materials can name a grade of API Spec 13A in the order, while every other additive is bought on the supplier's data sheet.
How Additives Are Tested and Dosed in the Field#
Additives are dosed by field tests on the mud, following API RP 13B-1 (6th edition, 2026) for water-based fluids and API RP 13B-2 (6th edition, 2023, with Addendum 1 of 2025) for nonaqueous fluids.
Alkalinity, hardness and Garrett Gas Train results set the treatment for alkalinity, calcium and sulfide, the work of the chemical-control classes. Laboratory tests of additives and fluids follow API RP 13I (9th edition (2020), with Addendum 1 of 2023).
No API or ISO standard exists for lubricity, so lubricants are compared on a lubricity tester under one fixed procedure. The mud balance, viscometer, filter press and titrations belong to the field and laboratory tests that check the effect of every other class.
Offshore Discharge and Notification Status by Additive Class#
On the US Outer Continental Shelf, 40 CFR 435.13 regulates the discharged water-based fluid as a whole, with no limit for any single additive. Water-based fluids may be discharged only beyond 3 miles (4.8 km) from shore, with a suspended particulate phase 96-hour LC50 of at least 3 % by volume, no free oil and no diesel oil.
The one material-level rule applies to stock barite, the barite used to formulate the fluid: it must contain no more than 1 mg/kg mercury and 3 mg/kg cadmium on a dry-weight basis. Part 435 was last amended on January 4, 2021 (eCFR).
In the North-East Atlantic, the PLONOR list of substances that pose little or no risk to the environment (OSPAR Agreement 2013-06, Update 2026) names single substances, not classes. One class can therefore hold listed and unlisted materials side by side.
The table below compares the 15 classes by the materials that carry an API Spec 13A grade and by PLONOR examples.
| Class | API Spec 13A materials (grade names) | PLONOR examples (OSPAR Agreement 2013-06, Update 2026) |
|---|---|---|
| Weighting agents | Barite (Barite 4.2 g/mL and Barite 4.1 g/mL), hematite | Barite, calcium carbonate, ilmenite, iron oxides including hematite and manganese tetraoxide listed; cesium formate not listed |
| Viscosifiers | Bentonite, non-treated bentonite, OCMA-grade bentonite, attapulgite, sepiolite, xanthan gum | Organoclays not listed by name |
| Fluid-loss additives | CMC-LVT, CMC-HVT, starch, PAC-LV, PAC-HV | Polyanionic cellulose not listed by name |
| Shale inhibitors | No API 13A grade | PHPA not listed |
| Lost circulation materials | No API 13A grade | Product-specific |
| Thinners and deflocculants | No API 13A grade | Sodium lignosulfonate, calcium lignosulfonate, iron lignosulfonates and SAPP listed; chrome lignosulfonate not named |
| Emulsifiers and wetting agents | No API 13A grade | Base oils not listed |
| Lubricants | No API 13A grade | Product-specific |
| pH and alkalinity control | No API 13A grade | Soda ash and sodium bicarbonate listed; caustic soda and caustic potash not listed |
| Biocides | No API 13A grade | Glutaraldehyde, THPS and CMIT/MIT not listed |
| Corrosion control | No API 13A grade | Sodium sulfite, sodium bisulfite, sodium metabisulfite, ammonium bisulfite and iron oxide (Fe3O4) listed; zinc oxide and zinc carbonates not listed |
| Defoamers and foaming agents | No API 13A grade | Product-specific |
| Flocculants | No API 13A grade | Polyacrylamide not listed |
| Spotting fluids | No API 13A grade | Product-specific |
| Surfactants | No API 13A grade | Product-specific |
Examples only, in the class order of the main table; US offshore limits apply to the whole discharged fluid, not to single additives.
The Offshore Chemical Notification Scheme (OCNS) of the UK and the Netherlands ranks offshore chemicals by hazard rather than by class. Products assessed with the CHARM model receive a hazard-quotient band from Gold (lowest hazard) through Silver, White, Blue and Orange to Purple, and products outside CHARM receive an OCNS group from A (most hazardous) to E. A new harmonized offshore chemical notification format (HOCNF) form applies, with compliance required by December 1, 2025 (Cefas bulletin of September 24, 2025).
OSPAR Decision 2000/3 adds two rules for the drilling fluid itself: no diesel-based fluids, and no discharge of cuttings carrying more than 1 % oil by weight on dry cuttings, since 2001.
How Drilling Fluid Additives Are Bought: Grades and Documents#
Drilling fluid additives are bought by material, grade and document: an API 13A grade where one exists, a certificate of analysis and a safety data sheet for every product, and mercury and cadmium results for offshore barite.
Drilling fluid additive suppliers are compared by their documents rather than their brands. Offers from drilling fluid additive suppliers that quote the same grade, the same documents and the same delivery point can be compared line by line.
Quantities are ordered in the unit each material ships in: sacks and big bags for powders, tonnes for bulk barite and bentonite, and barrels for liquid additives.
Classes without an API grade, from lubricants to biocides, are bought on the supplier's data sheet. The buyer asks which test the data sheet reports, so that two products are compared on the same method.
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Drilling Fluid Additives Beyond the 15 Classes#
Drilling fluid additives stop at the drilling fluid: cement, completion and production chemistry follow other rules and are outside this reference.
Named analyst estimates of the drilling fluid additives market differ widely between publishers. They are never merged with estimates for the drilling fluids market as a whole, because the two cover different products.
Additives for the cement that bonds casing in place belong to cementing, a separate field. Clear brines and packer fluids are completion fluids, not drilling fluids.
Additives that belong to two classes#
Six materials appear in two additive classes because a class names a task, not a chemical. The six are listed below with both of their classes.
- Lignite: thinner and fluid-loss additive.
- PHPA: shale inhibitor and clear-water flocculant.
- Graphite: lost circulation material and solid lubricant.
- Mica: lost circulation material and solid lubricant.
- Sized calcium carbonate: weighting agent and bridging solid.
- Lime: alkalinity agent and calcium source of oil-mud emulsifiers.
Each material page names both uses. The dose for each use follows the class it serves.
Temperature stabilizers and stress-cage materials#
A service-company additive catalog lists two categories beyond these 15 classes, temperature stabilizers and wellbore strengthening materials, and this reference treats them with high-pressure, high-temperature wells and with lost circulation.
Temperature limits are product values, so they appear on the class hubs next to the product that carries them. Wellbore strengthening uses sized solids, such as resilient graphitic carbon and sized calcium carbonate, as a pre-treatment against losses.
The stress cage concept comes from Alberty and McLean (SPE 90493, 2004), and fracture closure stress from Dupriest (SPE/IADC 92192, 2005). No single standard preventive test exists for wellbore strengthening (AADE-14-FTCE-25, 2014).