Oil-based mud (OBM) is a drilling fluid whose continuous phase is diesel, mineral oil or another oil, with brine emulsified into it as droplets, and US rules define it by that oil phase (40 CFR 435.11). Like any drilling fluid, it carries cuttings and balances formation pressure, but its oil phase keeps free water off the hole wall.
A 15 lb/gal (1.80 sg) laboratory oil-based mud combines eight components in one barrel, with 377 lb/bbl (1,076 kg/m3) of barite as the largest (Mahmoud et al., Scientific Reports, 2024). It is chosen for reactive shale and hot, high-pressure sections and has been run above 500 degF (260 degC).
The emulsified brine carries 250,000 to 300,000 ppm water-phase salinity in most drilling environments. Offshore, US rules allow no discharge of whole mud, OSPAR caps oil on dry cuttings at 1 % and Norway caps base fluid at 10 g/kg dry mass.
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.
The identity block below lists the names, definition and test standards of oil-based mud.
| Attribute | Value |
|---|---|
| System name | oil-based mud (OBM) |
| Synonyms | oil-base mud, oil mud, diesel oil mud, mineral oil mud |
| Fluid class | non-aqueous fluid (NAF) |
| US definition | 40 CFR 435.11(l)(2)(i) |
| Continuous phase | diesel, mineral oil or other oil |
| Internal phase | calcium chloride brine |
| Field test standard | API RP 13B-2 (6th edition, 2023) |
| ISO counterpart | ISO 10414-2 |
What Is Oil-Based Mud?#
Oil-based mud is a non-aqueous drilling fluid in which oil is the continuous, wetting phase and brine is the internal phase. US offshore rules class a fluid as oil-based when its continuous phase is diesel oil, mineral oil or some other oil and it contains no synthetic material or enhanced mineral oil (40 CFR 435.11(l)(2)(i)).
The IADC Drilling Manual sorts the types of drilling fluids into three classes, pneumatic, water-based and non-aqueous, and places oil-based mud with synthetic-based mud in the non-aqueous class. Grouping oil-based systems among the types of drilling fluids by continuous phase decides their field tests and discharge rules.
All-oil and emulsified-brine muds#
The older split of oil muds into oil-base mud and invert-emulsion mud by water content is no longer practical, and oil-based mud today means an emulsified-brine system. All-oil systems without a brine phase still exist, but the brine gives oil-based mud its osmotic control of shale, and every composition below refers to the emulsified-brine system.
What Is Oil-Based Mud Made Of?#
Oil-based mud is made of a base oil, an emulsified calcium chloride brine, primary and secondary emulsifiers, lime, an organophilic clay gellant, a fluid-loss additive such as organophilic lignite, and barite. One laboratory diesel mud combines these eight components in a single barrel (Mahmoud et al., Scientific Reports, 2024), each with one function.
A 15 lb/gal diesel oil-based mud, component by component#
Barite is the largest component of the example mud by mass and diesel the second, and the eight components sum to within 0.3 % of the 630 lb (1,797 kg/m3) a barrel of 15.0 lb/gal mud weighs.
The brine row splits into 16.4 lb/bbl (46.7 kg/m3) of calcium chloride and 49.1 lb/bbl (140.2 kg/m3) of water, since the brine is 25 % CaCl2 by mass. The amounts are one sourced laboratory example, not a typical field range.
The table below lists each component of the example mud with its function and amount per barrel.
| Component | Function | Amount, lb/bbl (kg/m3) |
|---|---|---|
| diesel | continuous phase | 154.46 (440.7) |
| primary emulsifier | emulsion | 8 (22.8) |
| Secondary emulsifier | oil-wetting of solids | 6 (17.1) |
| lime | soap activation, alkalinity | 6 (17.1) |
| calcium chloride brine, 25 % CaCl2 by mass | internal phase | 65.53 (187.0) |
| organoclay | gellant | 7 (20.0) |
| organophilic lignite | fluid-loss control | 8 (22.8) |
| barite | weighting agent | 377 (1,076) |
| Total | eight components | 631.99 (1,803) |
Mahmoud et al., Scientific Reports 2024; laboratory mud aged and tested at 275 degF (135 degC); kg/m3 calculated with 1 lb/bbl = 2.853 kg/m3.
Base oil: diesel or mineral oil#
Two base oils define oil-based mud: diesel, the distillate fuel grade of ASTM D975-91 (40 CFR 435.11(i)), and conventional mineral oil, which the same rule puts at about 0.35 % PAH by mass as phenanthrene.
OGP Report 396 (IOGP, 2009) places diesel and conventional mineral oil in base-fluid Group I (high aromatic) and low-toxicity mineral oil in Group II (medium aromatic). "Fuels, diesel" (CAS 68334-30-5) is not on the California Proposition 65 list, while diesel engine exhaust, benzene, ethylbenzene and naphthalene are listed (OEHHA list version 2026-07-31, checked 2026-10-27). A change from diesel to another base oil re-checks the emulsifier package, because emulsifier and wetting-agent solubility may differ from diesel (AADE, 2018).
The brine phase and its salinity#
Water-phase salinity of oil-based mud runs at 250,000 to 300,000 ppm in most drilling environments, about 25 to 30 % CaCl2 by mass in the water phase (AADE-07-NTCE-22). The droplets act as osmotic cells behind a semipermeable emulsifier film, so water moves from shale to mud when the brine has the lower activity (Chenevert, JPT, 1970).
Sections drilled near salt run 380,000 to 400,000 ppm, and above 400,000 ppm the same paper reports emulsion instability and water-wet solids. API RP 13B-2 derives water-phase salinity from the whole-mud chloride and calcium contents and the retort water volume.
Emulsifiers, gellants and fluid-loss chemicals#
Primary emulsifiers of oil-based mud are calcium fatty-acid soaps formed from fatty acid and lime, and secondary emulsifiers are polyamides, amidoamines or imidazolines that oil-wet the solids. Tall oil fatty acids and lecithin are two emulsifier raw materials.
Organophilic clay is the gellant: a clay treated with a quaternary amine so that it disperses in oil. Plate-shaped clays build rheology and filter cake, rod-shaped clays gel only. API Spec 13A has no section for organoclay, emulsifiers, calcium chloride or lime, so only the barite carries an API Spec 13A grade.
Fluid loss control additives in the example mud come down to one, organophilic lignite, an amine-treated lignite that disperses in oil. Other fluid loss control additives for oil-based mud include sulfonated asphalt, asphaltic resins and polymeric filtration reducers.
How Oil-Water Ratio and Other Properties Are Set#
Oil-water ratio is the split between oil and water in the liquid phase of an oil-based mud, read from the retort, and in the EPA reference fluid the oil share rises with mud weight. That fluid runs 75/25 at 9.0 lb/gal (1.08 sg), 80/20 at 11.5 lb/gal (1.38 sg) and 85/15 at 14.5 lb/gal (1.74 sg) (40 CFR 435, Subpart A, Appendix 8).
The reference fluid is a C16-C18 internal olefin synthetic mud used for EPA compliance testing, not an oil-based mud, so its ratios are reference points rather than limits for oil-based mud.
The retort reports oil and water as volume percentages of the whole mud, and the oil-water ratio expresses each as a share of their sum (AADE, 2015).
Rheology, emulsion and filtration readings#
Rheology of an oil-based mud is read at 120 or 150 degF (48.9 or 65.6 degC), because the viscosity of oil muds changes with temperature (AADE, 2015).
Emulsion strength is read as an electrical stability voltage. Two laboratory versions of the example mud read 863 and 942 V at ambient temperature (Mahmoud et al., Scientific Reports, 2024), a condition that does not compare like for like with field readings, while the EPA reference fluid must exceed 300 V.
Filtration of oil-based mud is measured under high-temperature, high-pressure (HTHP) conditions by API RP 13B-2. Plastic viscosity, yield point and gel strength, the core values of drilling fluid rheology, come from the same heated dial readings.
Where Is Oil-Based Mud Used, and Where Not?#
Oil-based mud is used where a water mud would destabilize the hole or break down at temperature, above all in reactive shale and HPHT sections, and not where its base oil or cuttings may not be discharged. Diesel muds are out in the OSPAR area, where Decision 2000/3 allows no diesel-based fluids.
In US offshore waters, whole oil-based mud is never discharged, and its diesel and mineral-oil base fluids cannot meet the stock limits set for synthetic-based fluids, so oil-based mud wells there run zero discharge of mud and cuttings.
High-temperature wells and reactive shale#
Oil-based mud has been run in high-temperature, high-pressure wells above 500 degF (260 degC) and above 18.0 lb/gal (2.16 sg), according to an AADE technical paper. Among high-temperature (HPHT) drilling fluids, an oil-based mud in an Indonesian well reached a bottomhole static temperature of 363.9 degF (184.4 degC) at 17,080 ft (5,206 m) measured depth (AADE-26-FTCE-053).
Reactive shale stays stable because oil-based mud controls water transfer through its brine salinity, which a water mud cannot do. Drilling Contractor (2000) names three stabilizing factors of oil-based mud in shale: mud pressure support, capillary entry pressure and osmotic dehydration.
US land and North Sea practice#
Diesel-based invert emulsion is the most common oil-based system in US land unconventional wells (AADE, 2018), while ultra-clean mineral oils predominate as base fluids in the North Sea (AADE, 2008). For US land wells, the 2018 AADE paper proposes a specification for diesel alternatives: BTEX not detectable, total aromatics below 0.5 % by mass and flash point above 140 degF (60 degC).
Advantages and Limits of Oil-Based Mud#
Oil-based mud gives shale stability, temperature tolerance, lubricity and freedom from bit balling, and it costs more per barrel, cannot be discharged whole and needs its brine, emulsion and solids kept in balance.
High-fluid-loss squeeze materials for lost circulation may underperform in non-aqueous fluids (AADE-14-FTCE-25), and in cold deepwater risers the viscosity of water-based and oil-based muds rises exponentially as temperature falls (Offshore magazine).
The table below sums up each advantage and limit of oil-based mud with its basis.
| Attribute | Oil-based mud | Basis |
|---|---|---|
| Shale stability | water transfer controlled by brine salinity | balanced activity (Chenevert, JPT 1970) |
| Temperature tolerance | run in high-temperature, high-pressure wells | AADE technical paper |
| Bit balling | does not normally occur | invert emulsion |
| Lubricity | oil phase lubricates | diesel and crude oil |
| Discharge | whole mud never discharged offshore in the US; diesel muds prohibited in the OSPAR area | 40 CFR 435.13; OSPAR Decision 2000/3 |
| Cost | higher per bbl than water-based mud in the EPA rule record | Federal Register, 2001 |
| Lost circulation | high-fluid-loss squeeze materials may underperform | AADE-14-FTCE-25 |
| Cold risers | viscosity rises as temperature falls | Offshore magazine |
Relaxed-filtrate oil muds#
A relaxed-filtrate oil mud omits the fatty-acid soap and lime and keeps organoclay and fluid-loss additives to a minimum, which raises the penetration rate at the price of a higher risk of differential sticking. It is the opposite of the fully treated example mud above.
Density under downhole temperature and pressure#
The drilling fluid density of an oil-based mud changes downhole because its oil compresses under pressure and expands with heat. Mineral-oil muds are more compressible and expand more than diesel muds (Peters et al., SPE 1990), so the surface reading of drilling fluid density differs from the density acting at depth.
How Oil-Based Mud Is Maintained and What Upsets It#
An oil-based mud is maintained by holding its oil-water ratio, water-phase salinity, emulsifier and lime levels and solids within the mud program, and four upsets push it out of balance.
The four upsets and what each does are listed below.
- Water influx: lowers the oil-water ratio.
- Salinity overshoot past the near-salt band: emulsion instability and water-wet solids.
- Fine solids: raise the oil-wetting demand on the secondary emulsifier.
- Acid gases (CO2, H2S): consume the lime reserve.
Water-wet solids end the balance: solids lose their oil coat and the emulsion weakens. Secondary emulsifiers prevent water-wet solids in oil-based mud by oil-wetting barite and drilled solids.
Daily retort, emulsion and alkalinity checks#
Field checks of oil-based mud follow API RP 13B-2, 6th edition (2023) with Addendum 1 (2025), "Field Testing Nonaqueous-based Drilling Fluids", with ISO 10414-2 as the ISO counterpart. Laboratory testing follows API RP 13I, 9th edition (2020) with Addendum 1 (2023).
The table below lists the daily field checks and what each one shows.
| Check | What it shows |
|---|---|
| mud retort | oil, water and solids by volume |
| oil-water ratio from retort volumes | oil share of the liquid phase |
| electrical stability | emulsion strength, in volts |
| alkalinity and lime content | whole-mud alkalinity Pom and excess lime |
| Water-phase chlorides and calcium | water-phase salinity |
| Rheology | viscosity, yield point and gels at the reporting temperature |
| HTHP filtration | filtrate volume and filter cake |
Field checks under API RP 13B-2, the field-testing practice for nonaqueous muds.
CO2, H2S and excess lime#
Lime buffers oil-based mud against carbon dioxide and hydrogen sulfide by reacting with both acid gases. With hydrogen sulfide it forms calcium sulfide in a reversible reaction (Ca(OH)2 + H2S -> CaS + 2 H2O), and with carbon dioxide it forms calcium carbonate (Ca(OH)2 + CO2 -> CaCO3 + H2O). In a non-aqueous mud, excess lime in lb/bbl is 1.3 times the whole-mud alkalinity Pom (AADE, 2015), and the water-based lime-mud relation does not apply.
A falling Pom shows the lime reserve being spent on CO2 and H2S. Contamination of the mud by CO2 and H2S is treated by restoring that lime reserve.
Environmental Status of Oil-Based Mud by Jurisdiction#
Three jurisdictions set the offshore rules for oil-based mud: the United States bars discharge of whole mud and diesel, OSPAR bans diesel-based fluids and caps oil on cuttings, and Norway caps base fluid on cuttings. US onshore and coastal wells follow two further rules, listed with the offshore ones below.
The table below compares the discharge rules for oil-based mud by jurisdiction, instrument and section.
| Jurisdiction | Instrument and section | Rule for oil-based mud | Rule set |
|---|---|---|---|
| US offshore (Subpart A) | 40 CFR 435.13 (BAT), 435.15 (NSPS) | No discharge of whole non-aqueous mud or of diesel oil; no discharge within 3 mi (4.8 km), Alaskan facilities follow the beyond-3-mi limits; diesel and mineral-oil base fluids cannot meet the stock limits for synthetic fluids | US offshore discharge rules (40 CFR 435) |
| US coastal (Subpart D) | 40 CFR 435.43 | No discharge of drilling fluids, cuttings or dewatering effluent except in Cook Inlet; Cook Inlet non-aqueous cuttings only by technical exemption | Coastal subcategory |
| US onshore waste | 40 CFR 261.4(b)(5) | Drilling fluids and other exploration and production wastes excluded from RCRA hazardous waste; state rules apply | drilling waste management |
| North-East Atlantic | OSPAR Decision 2000/3 | No diesel-based fluids; no discharge of cuttings above 1 % oil by weight on dry cuttings, since 2001 | OSPAR rules for offshore drilling fluids |
| Norway | Activities Regulations s.68 (last changed 2021-01-01) | No discharge of cuttings with more than 10 g/kg dry mass of base fluid or formation oil | Havtil regulations |
The same rules decide the fate of drill cuttings and oil on cuttings from every oil-based mud well.
Which oil-based mud components OSPAR rates as low risk#
Barite, calcium chloride and lecithin are the three oil-based mud components on the OSPAR PLONOR list, while organoclays, tall oil fatty acids and base oils are not listed by name (OSPAR Agreement 2013-06, Update 2026). PLONOR stands for substances that pose little or no risk to the environment.
The table below lists the PLONOR status of each component class of oil-based mud.
| Component | PLONOR (OSPAR Agreement 2013-06, Update 2026) |
|---|---|
| Barite | listed as barite and as barium sulfate |
| Calcium chloride | listed (CAS 10043-52-4) |
| Lecithin (emulsifier) | listed (CAS 8002-43-5) |
| Organoclays | not listed |
| Tall oil fatty acids (emulsifier) | not listed |
| Base oils | not listed by name |
Component status on the OSPAR PLONOR list, read from the Cefas-hosted list.
What Drives the Cost of Oil-Based Mud?#
The cost of an oil-based mud follows five quote factors: base oil, mud weight, brine salt, the emulsifier and gellant package, and cuttings handling. The EPA used USD 70 to 90 per bbl (USD 440 to 566 per m3) for oil-based fluids in 2000 to 2001, a dated record value for weighing the cost of oil-based mud against water-based mud (Federal Register, 2001-01-22).
Diesel costs less than mineral oil, and both cost less than synthetic base fluids (AADE, 2008). After the 2002 US offshore permit, some high-performance shelf wells moved from synthetic-based back to oil-based mud with zero discharge, on cost (AADE, 2008).
The five quote factors are listed below.
- Base oil: diesel or mineral oil.
- Mud weight: the barite share of each barrel.
- Brine salt: calcium chloride by target salinity.
- Emulsifier and gellant package: primary and secondary emulsifiers, lime and organoclay.
- Cuttings handling: transport and treatment under zero discharge.
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How Oil-Based Mud Compares with Other Types of Drilling Fluids#
Oil-based mud sits between water-based mud, which costs less and may be discharged offshore in the US under toxicity limits, and synthetic-based mud, whose cuttings may be discharged within retention limits. The table below compares the three neighbor systems by continuous phase and US offshore discharge.
| System | Continuous phase | US offshore discharge |
|---|---|---|
| Oil-based mud | diesel, mineral oil or other oil | no discharge of whole mud; base fluids cannot meet the stock limits for cuttings |
| water-based mud | water or brine | mud and cuttings beyond 3 mi if the SPP 96-h LC50 is at least 3 % by volume, with no free oil and no diesel |
| synthetic-based mud | synthetic material (40 CFR 435.11(kk)) | cuttings within 6.9 or 9.4 g base fluid per 100 g wet cuttings; whole mud never |
| base fluids for non-aqueous muds | diesel, mineral oil, olefins, paraffins and esters | set by the base fluid |
Performance, cost and discharge trade-offs separate water-based vs oil-based mud and oil-based vs synthetic-based mud.
Oil-based packer fluids left in a completed well belong to completion chemistry, a separate field not covered here.
When a water mud replaces oil#
Water-based mud replaces oil-based mud where discharge rules or cost outweigh the shale and temperature needs of the well. US rules let water-based mud and cuttings go overboard when the whole mud passes the SPP toxicity test, carries no free oil and contains no diesel (40 CFR 435.13).
Silicate muds are one water-based alternative: nondispersed silicate polymer fluids returned in the 1990s as a replacement for oil-based mud in shale.
Synthetic and ester fluids as successors#
Synthetic-based muds entered the North Sea in the early 1990s and the Gulf of Mexico in the mid-1990s (AADE, 2008), and they run on almost all deepwater Gulf of Mexico projects in the data to 2006.
The name "oil mud" is not used for synthetic-based muds, although both are non-aqueous invert emulsions. They differ in the base fluid (esters, olefins or paraffins), not in the emulsified-brine structure.
Does a mineral-oil mud count as synthetic?#
No, not in the US: 40 CFR 435.11(kk) limits synthetic material to reaction products of purified feedstock, and the oil-based definition excludes enhanced mineral oil, which carries 0.001 % PAH by mass or lower as phenanthrene. A conventional mineral-oil mud therefore stays an oil-based mud under US rules, with no route to the cuttings allowance of synthetic-based mud.