Drilling fluids come in three types, named for their continuous phase: water-based fluids on fresh water or brine, non-aqueous fluids on oil or a synthetic base fluid, and pneumatic fluids on air or gas (IADC Drilling Manual). Each type holds several systems, and the system chosen for a well turns a plain base into a working drilling fluid.
The base also sets the starting density. Fresh water weighs 8.34 lb/gal (1.00 sg; 999 kg/m3) and seawater about 8.55 lb/gal (1.02 sg; 1,025 kg/m3).
Water-based systems differ in how strongly they inhibit reactive shale, non-aqueous systems differ by base fluid, and saturated cesium formate brine reaches 19.2 lb/gal (2.30 sg) without any solids. Formation, temperature, depth and discharge rules decide the system: on the US Outer Continental Shelf, water-based fluid may be discharged under limits while whole non-aqueous fluid never is, and the North-East Atlantic allows no diesel-based fluids.
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 the Three Types of Drilling Fluids?#
The three types of drilling mud are water-based mud, with water or brine as the continuous phase; non-aqueous mud, with oil or a synthetic fluid; and pneumatic fluid, in which compressed air or gas carries the cuttings. In water-based mud, water or saltwater is the major liquid phase and also the wetting, or external, phase. Water-based muds fall into three subclasses: non-inhibitive, inhibitive and polymer muds.
US rules separate the two non-aqueous families by their continuous phase. Under 40 CFR 435.11, an oil-based fluid has a continuous phase of diesel oil, mineral oil or some other oil with no synthetic material or enhanced mineral oil, and a synthetic-based fluid has a continuous phase of synthetic material, the reaction product of a purified chemical feedstock. OSPAR Decision 2000/3 draws the line elsewhere: its synthetic fluids also include highly refined mineral oils and fluids of vegetable or animal origin, so a US and a European "synthetic" mud are not the same fluid. Pneumatic fluids cover dry air, gas, mist, foam and aerated mud.
Every type is a base plus additives, such as viscosifiers, weighting agents and fluid-loss additives. The classes of drilling fluid additives recur across all three types, with the base deciding which members of each class work. Completion and workover fluids, clear brines and packer fluids are completion fluids, a separate field from drilling fluids, and are not covered here.
Abbreviations for fluid systems: from WBM to RDF#
Eight abbreviations name the drilling fluid systems in the IADC drilling fluids chapter, and the list below gives each in full.
- WBM: water-based mud
- OBM: oil-based mud
- SBM: synthetic-based mud
- NAF: non-aqueous fluid, the collective term for OBM and SBM
- IEF: invert emulsion fluid
- HPWBM: high-performance water-based mud
- DIF: drill-in fluid
- RDF: reservoir drill-in fluid
Drilling Fluid Systems Compared: Continuous Phase, Key Components, Weight Range and Temperature Data#
Each drilling fluid system is defined by its continuous phase and key components: water-based systems range from spud mud to formate brines, non-aqueous systems differ by base fluid, and pneumatic systems by the liquid in the air. The table below compares all 15 system and topic pages by type, base, key components, density data and temperature data.
Send one specification to independent suppliers of drilling fluid materials. request supplier quotes
| System | Type | Continuous phase and base | Key components | Density data (source) | Temperature data (test condition or field case, source) |
|---|---|---|---|---|---|
| Water-based mud | Water-based | Fresh water, seawater or brine | Bentonite, polymers, alkalinity control | Fresh water 8.34 lb/gal (1.00 sg; 999 kg/m3); seawater 8.55 lb/gal (1.02 sg; 1,025 kg/m3) (IADC) | Varies by system (rows below) |
| Spud and native muds | Water-based | Fresh water or seawater | Bentonite flocculated with lime onshore; guar gum or salt gel offshore | Set by the well program | Shallow hole section |
| Polymer drilling fluids (LSND) | Water-based | Fresh water | Polymers at low solids | Set by the well program | Product-specific |
| KCl-polymer muds | Water-based, inhibitive | Potassium chloride brine | Potassium chloride, xanthan gum and PHPA in place of bentonite | Set by the well program | Product-specific |
| Dispersed muds | Water-based | Fresh water | Bentonite with lignosulfonate and lignite; lime or gypsum | Chrome-free field mud 16.7 lb/gal (2.00 sg; 2,001 kg/m3), weighable to 19.2 lb/gal (2.30 sg; 2,301 kg/m3) (AADE paper) | Ferrochrome lignosulfonate bentonite mud stable at 350 degF (177 degC), decomposing at 450 degF (232 degC) (Zilch et al. 1991, as cited by AADE); chrome-free field mud stable at 400 degF (204 degC) |
| Salt muds | Water-based | Saturated salt water, saltwater, seawater or brackish water | Salt-tolerant clays and polymers | Set by the well program | Product-specific |
| High-performance water-based muds | Water-based, inhibitive | Brine, such as potassium chloride brine | Glycols, amines, encapsulators | Set by the well program | North Sea KCl/glycol mud formulable to 425 degF (218 degC) (AADE paper) |
| Reservoir drill-in fluids | Water-based or invert emulsion | Brine or invert emulsion | Sized calcium carbonate or salt, polymers | Formate drill-in fluid 17.4 lb/gal (2.09 sg; 2,090 kg/m3) (AADE-24-FTCE-047) | Same fluid drilled at 342 degF (172 degC), Kristin field (AADE-24-FTCE-047) |
| Formate brines | Water-based brine | Sodium, potassium or cesium formate brine | Carbonate and bicarbonate buffer; no barite | Density from dissolved salt, no solids | Cesium formate brine documented at 455 degF (235 degC) for 38 days (AADE 2018) |
| Oil-based mud | Non-aqueous | Diesel, mineral or other oil (40 CFR 435.11) | Emulsified calcium chloride brine, emulsifiers, organoclay, lime | Set by the well program | Product-specific |
| Synthetic-based mud | Non-aqueous | Synthetic material (40 CFR 435.11) | Olefins, esters or paraffins as base; emulsifier package as in oil-based mud | Set by the well program | Product-specific |
| Base fluids for non-aqueous muds | Non-aqueous component | Diesel, mineral oil, olefins, paraffins, esters | Grouped by aromatics content (OGP Groups I to III) | Set by the mud formulation | Pure vegetable esters stable to about 225 to perhaps 320 degF (107 to 160 degC) (EPA memorandum 2003) |
| Foam drilling fluids | Pneumatic | Air, nitrogen or gas | Foaming agents and defoamers; mist, foam, aerated mud | Uphole velocity replaces density as the design figure | Product-specific |
| Functions of drilling fluid | All types | Topic page | The functions every system performs | Applies to every system | Applies to every system |
| Select a drilling fluid system | All types | Topic page | Selection method by well and location | Applies to every system | Applies to every system |
Temperature data are test conditions or documented field and laboratory cases, not product limits.
The 13 systems in the table differ in purpose as follows.
- Water-based mud: the parent family of the next eight systems, with water or saltwater as the external phase.
- Spud and native muds: mud for drilling from the surface to a shallow depth, where wells start with simple, low-density fluid.
- Polymer drilling fluids (LSND): water-based muds with low solids and no chemical clay deflocculant, the two features the name low-solids non-dispersed describes.
- KCl-polymer muds: inhibitive muds in which potassium, not bentonite, carries the control of reactive shale.
- Dispersed muds: muds in which lignosulfonate and lignite deflocculate the clay; lime muds and gyp muds add calcium.
- Salt muds: water-based muds whose base ranges from brackish water and seawater to saturated salt water.
- High-performance water-based muds: inhibitive systems developed as water-based alternatives to oil-based mud.
- Reservoir drill-in fluids: fluids used to drill the reservoir section only.
- Formate brines: brines of sodium, potassium or cesium formate that carry density in solution.
- Oil-based mud: invert emulsions in which brine droplets sit inside diesel or mineral oil.
- Synthetic-based mud: invert emulsions on a synthetic base fluid, defined in US rules by the synthetic material of its continuous phase.
- Base fluids for non-aqueous muds: the oils and synthetic fluids themselves, ranked by aromatics content.
- Foam drilling fluids: pneumatic systems from dry air through mist and foam to aerated mud.
Two further pages cover every system at once: the functions a drilling fluid performs in the well and the method for selecting a system. Each temperature shows what one documented fluid withstood, not a rating for its whole system.
How Inhibition Separates the Water-Based Systems#
Water-based systems differ in how strongly they inhibit reactive shale: freshwater muds are non-inhibitive, lignosulfonate and lignite muds slightly inhibitive, calcium muds fairly inhibitive, and potassium and silicate muds moderately inhibitive. No water-based system reaches the rank of a balanced-activity oil mud, which counts as highly inhibitive. Five landmark papers trace the work on inhibitive water-based chemistry.
O'Brien and Chenevert described stabilizing sensitive shales with inhibited, potassium-based drilling fluids in JPT in 1973, and Clark, Scheuerman, Rath and Van Laar introduced polyacrylamide/potassium chloride mud for water-sensitive shales in JPT in 1976. Twynam, Caldwell and Meads covered glycol-enhanced muds in SPE 27451 (1994), and van Oort and co-authors covered silicate fluids in IADC/SPE 35059 (1996). Dye and co-authors (SPE/IADC 92367, 2005) and Patel, Stamatakis, Young and Friedheim (SPE 106476, 2007), the latter asking whether inhibitive water-based fluids can replace oil-based muds, framed the high-performance water-based mud.
Environmental rules limit the dispersed systems as well. Chrome lignosulfonates and lignites are not permissible in many areas, according to an AADE paper on chrome-free dispersed mud, which documents the chrome-free field mud in the table above. Inhibition in today's water-based systems comes from additives, such as potassium salts, glycols, amines and silicates, rather than from the base water.
Where Non-Aqueous Systems Fit: Diesel, Mineral Oil and Synthetic Base Fluids#
Non-aqueous systems control shale by the salinity of their emulsified water phase, which a water-based mud cannot do, and they divide by base fluid into diesel and mineral-oil muds and synthetic-based muds. The base fluids fall into three groups by total aromatics content of the base fluid (IOGP Report 396, 2009, citing Report 342, 2003). Group I, diesel and conventional mineral oil, holds 5 to 35 % aromatics; Group II, low-toxicity mineral oil, 0.5 to 5 %; and Group III, esters, olefins, paraffins and highly processed mineral oil, below 0.5 % aromatics with polycyclic aromatic hydrocarbons (PAH) below 0.001 %.
Synthetic-based muds reached the North Sea in the early 1990s and the Gulf of Mexico in the mid-1990s, according to an AADE paper on synthetic-based fluid use.
Cost separates the types as well. EPA's 2001 rulemaking used about USD 45 per bbl (USD 283 per m3) for water-based fluid, USD 70 to 90 per bbl (USD 440 to 566 per m3) for oil-based fluid and USD 160 to 300 per bbl (USD 1,006 to 1,887 per m3) for synthetic-based fluid, values from 2000-2001 rather than present-day prices (Federal Register, 2001-01-22). Unit cost is one of three trade-offs, next to performance and environmental impact, in the choice of water-based vs oil-based mud.
Density Without Solids: Salt and Formate Systems#
Salt and formate systems gain density from dissolved salt instead of solids, and saturated formate brines reach 11.1 lb/gal (1.33 sg) for sodium, 13.3 lb/gal (1.59 sg) for potassium and 19.2 lb/gal (2.30 sg) for cesium formate. Those values hold at 68 degF (20 degC) and equal 1,330, 1,590 and 2,300 kg/m3 (AADE-24-FTCE-047). Formate brines always run with a sodium or potassium carbonate and bicarbonate buffer, and they are never weighted with barite, which dissolves in potassium formate with a carbonate buffer.
Formates moved from trial to field use in about a decade. Sodium formate first drilled in coiled-tubing operations in the Netherlands in 1993, potassium formate served as a drill-in fluid in Norway within a year, and cesium formate entered a drilling fluid on the Huldra field in 2001 (AADE papers).
Offshore status splits the three formates. Potassium formate and sodium formate are on the PLONOR list (OSPAR Agreement 2013-06, Update 2026), and cesium formate is not.
Pneumatic Systems: Air, Mist, Foam and Aerated Mud#
Pneumatic drilling fluids lift cuttings with compressed air, nitrogen or gas instead of a liquid, and they range from dry air through mist and foam to aerated mud as liquid is added. Air drilling is faster than drilling with liquids and can eliminate lost circulation, but it gives no control over the inflow of formation fluids. Mist drilling is air drilling with a small water influx that the air carries out of the hole.
Pneumatic systems are designed by uphole velocity instead of density. Dry air needs about 3,000 to more than 7,500 ft/min (914 to 2,286 m/min), foam 200 to 400 ft/min (61 to 122 m/min) and stiff foam 100 to 200 ft/min (30 to 61 m/min) (Water Well Journal, 2023).
The air volume needed to lift cuttings rises with depth and hole size. Depth, hole size and water inflow therefore set the practical boundary between air vs mud drilling in a given hole.
Which System for Which Well: Formation, Temperature, Depth and Location#
Formation, temperature, depth and the discharge rules of the location decide which type of drilling fluid a well gets, and wells are spudded with simple low-density fluids that grow denser and more complex with depth. The seven well conditions below each point to a system.
- Surface hole: spud mud, bentonite flocculated with lime onshore or guar gum or salt gel offshore.
- Reactive shale: oil-based or synthetic-based mud, or an inhibitive potassium, glycol, silicate or high-performance water-based mud.
- High temperature: diesel-oil mud is a mud of choice for high-pressure, high-temperature (HPHT) zones, and chrome-free dispersed water-based mud has a documented high-temperature field case in south-eastern Hungary (AADE paper).
- US Gulf of Mexico: water-based mud dominates the shelf, and synthetic-based mud runs on almost all deepwater projects (AADE paper, data to 2006).
- North Sea: ultra-clean mineral oils were the predominant non-aqueous base fluids in 2008 (AADE paper).
- Reservoir section: a drill-in fluid of brine, sized solids and polymers, used for that section only.
- Dry formations with lost circulation: air, mist or foam.
IADC names 12 selection factors, from local practice, operator preference and the supplier's range through density, hole size, formation and wellbore stability, temperature and pressure, completion type and regional problems to logistics, cost and quality, and health, safety and environment.
Oil and gas wells are one setting among several. Outside them, the main settings for drilling fluids by application are HDD bores, water wells, geothermal wells, mineral exploration holes and foundation excavations.
Offshore Discharge Status by Fluid Type#
Discharge status follows the base fluid: water-based fluid and its cuttings may be discharged offshore under limits, whole non-aqueous fluid never, and non-aqueous cuttings only below a retention limit. The table below compares each fluid type on the US Outer Continental Shelf, under OSPAR Decision 2000/3 and on the PLONOR list.
| Fluid type | US Outer Continental Shelf (40 CFR 435.13) | North-East Atlantic (OSPAR Decision 2000/3) | PLONOR (OSPAR Agreement 2013-06, Update 2026) |
|---|---|---|---|
| Water-based fluid | Fluid and cuttings discharged beyond 3 miles (4.8 km) only; suspended particulate phase 96-h LC50 at least 3 % by volume; no free oil; no diesel oil; stock barite at most 1 mg/kg mercury and 3 mg/kg cadmium, dry weight | Decision covers organic-phase fluids, not water-based fluid | Barite and calcium carbonate listed |
| Oil-based fluid (diesel, mineral oil) | Whole fluid not discharged | No diesel-based fluids; no discharge of cuttings above 1 % oil on dry cuttings, since 2001 | Base oils not listed by name |
| Synthetic-based fluid | Whole fluid not discharged; cuttings at most 6.9 g (internal olefin type) or 9.4 g (ester) base fluid per 100 g wet cuttings | No discharge of cuttings above 1 % oil on dry cuttings, since 2001 | Base fluids not listed by name |
The toxicity limit applies to the suspended particulate phase of the whole drilling fluid, never to a single additive, and Alaskan facilities follow the same distance limit as the rest of the shelf. Coastal waters are stricter, with no discharge except in Cook Inlet.
Synthetic-based cuttings retention is a weighted average measured by EPA Method 1674. Diesel and mineral-oil muds cannot meet the US stock limits for base-fluid PAH content, sediment toxicity and biodegradation, so their cuttings are not discharged on the shelf. Norway sets its own oil-on-cuttings limit of 10 g/kg dry mass (Activities Regulations section 68).
Discharge is one of three environmental questions a fluid type raises. Cuttings toxicity and waste disposal are the other two parts of drilling fluids and the environment.
How Each Fluid Type Is Tested in the Field#
Water-based fluids are tested to API RP 13B-1 (6th edition, 2026) and oil-based and synthetic-based fluids to API RP 13B-2 (6th edition, 2023, with Addendum 1, 2025). Rheology is read at 120 degF (48.9 degC), or 150 degF (65.6 degC) for high-temperature wells, and HTHP filtration commonly runs at 275 to 325 degF (135 to 163 degC) and 500 psi (3,447 kPa) differential pressure (IADC Drilling Manual).
Electrical stability is a test of non-aqueous fluids only, because it checks the strength of the water-in-oil emulsion. Formate brines add pH, buffer and crystallization-temperature tests to ISO 13503-3:2022.
Density, rheology, filtration and solids are measured on every type. Those four readings form the core of drilling fluid testing on the rig.
Who Supplies and Runs Drilling Fluid Systems?#
Drilling fluid systems are supplied in two ways: service companies sell the system with mud engineering on the rig, and additive suppliers sell the materials by grade for the operator or contractor to mix.
Materials are bought by grade and document. API Spec 13A grades exist for barite, bentonite and 11 other materials, and a purchase specification names the material and grade, the quantity and unit, the packaging, the delivery point and the documents, such as a certificate of analysis, an SDS and the API Monogram where it applies.
The split between system service and material supply is the first filter when comparing drilling fluid companies.
Request supplier quotes
Send one specification to independent suppliers of drilling fluid materials.
Requests are forwarded to independent suppliers and service providers. No company pays to be listed or ranked here; see the editorial policy.
From Fluid Type to Additive Class: What Goes into Each System#
Every fluid type performs the same core functions, controlling subsurface pressure, carrying cuttings out and keeping the wellbore stable, and the additive classes in each system exist to serve them (IADC Drilling Manual).
The drilling fluid circulation system, with its pumps, pits and solids-control equipment, is rig equipment and is not covered here.
Metalworking "drilling fluids" used to cut metal are a separate field and are not covered here either.
Each system is checked against the same measures: density, rheology, filtration, solids and chemistry. Those five measures are the drilling fluid properties that the additive classes adjust.
Which clay is the base of a drilling mud?#
Sodium bentonite, a montmorillonite clay whose platelets hydrate and swell in fresh water, is the clay of water-based drilling mud. The swollen platelets build viscosity and gel strength and form a thin, low-permeability filter cake on the borehole wall.
Two other clays take over where bentonite fails. Attapulgite, known as salt gel or salt-water gel, builds viscosity in salt water, and organophilic clay viscosifies oil-based and synthetic-based muds.
Bentonite is the clay a water-based mud starts from. Grade, yield and dose decide how much bentonite in drilling fluids a given mud needs.