Drill Cuttings: Composition, Oil on Cuttings, Treatment and Disposal

Drill cuttings are the rock fragments a drilling fluid carries out of the hole, from clay-size particles near 0.002 mm to gravel over 30 mm (IOGP review reported in JPT, 2021). Offshore, they may be discharged only when the fluid left on them meets a limit set per jurisdiction (40 CFR 435.13; OSPAR Decision 2000/3).

The base fluid decides the route. Every drilling fluid that lifts cuttings to surface also coats them, so water-based, oil-based and synthetic-based muds leave cuttings with different discharge, treatment and disposal options.

Shakers alone left 10.2 % base fluid on cuttings in the data behind the 2001 US rule, and a cuttings dryer with fines removal cut that to 3.82 %. Thermomechanical cleaning brought oil-based cuttings to an average of 0.03 % oil in Norwegian field units. Treated cuttings then go to sea, into a deep formation, to shore in skips or to land treatment, each route under its own rules.

The four key oil-on-cuttings figures are listed below.

• US federal waters beyond 3 miles: 6.9 g of base fluid per 100 g of wet cuttings for C16-C18 internal olefin fluids (40 CFR 435.13).
• OSPAR area: no discharge above 1 % oil by weight on dry cuttings, since 2001 (OSPAR Decision 2000/3).
• Norway: no discharge above 10 g/kg dry mass of base fluid or formation oil (Activities Regulations s.68).
• US waters within 3 miles of shore: no discharge of drilling fluids or cuttings (40 CFR 435.13).

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 Drill Cuttings Made Of?#

Drill cuttings are made of the formation rock the bit breaks, from fine silt to gravel, plus the drilling fluid that stays on them after solids control separates them from the circulating mud (40 CFR 435.11(k)).

The same definition applies to coastal facilities under 40 CFR 435.41(m). Both rules treat cuttings as the principal solid waste stream a well returns while drilling, carried to surface by the fluid and separated from it at the rig.

Rock fragments, size and the fluid that clings to them#

Drill cuttings range from about 0.002 mm (2 um), the size of clay, to over 30 mm (1.18 in), the size of gravel (IOGP review reported in JPT, 2021). The rock fragment is only part of what reaches the shakers. Each cutting leaves the hole coated in the fluid that carried it, and solids control strips the free fluid but leaves a film on the surface. That retained film, not the rock, decides whether cuttings may be discharged. Seabed effects are the primary environmental concern of discharged cuttings with residual fluid, while the water-column risk is low because of dilution (IOGP review reported in JPT, 2021).

Cuttings must first reach surface, and the capacity of the fluid to lift them is called cuttings transport. Efficient cuttings transport depends first on annular velocity, hole angle and flow profile, and second on mud weight, cuttings size and pipe position. Geological description of cuttings samples for the well record is mud logging, a separate service from fluid and waste handling.

Cuttings from water-based and non-aqueous fluids#

The base fluid sets what happens to cuttings: in US federal waters beyond 3 miles, water-based fluid and its cuttings may be discharged, whole oil- and synthetic-based mud never, and non-aqueous cuttings only within a retention limit.

Water-based cuttings pass or fail with the mud they came from, through the toxicity of its suspended particulate phase (SPP), and must show no free oil (40 CFR 435.13). Non-aqueous cuttings pass only after the base fluid itself meets stock limits, and the whole non-aqueous fluid is never discharged (40 CFR 435.12 to 435.15).

One base fluid is barred outright. Diesel oil, defined in 40 CFR 435.11(i) as the distillate fuel oil grade of ASTM D975-91, may not be discharged with drilling fluid or with cuttings anywhere in US offshore and coastal waters (40 CFR 435.13, 435.15 and 435.43).

How Is Oil on Cuttings Measured and Limited?#

Oil on cuttings is measured by retorting a cuttings sample and weighing the base fluid driven off; US rules limit it per 100 g of wet cuttings, OSPAR and Norway per weight of dry cuttings.

The two bases differ by more than wording. A wet-basis number divides the oil by the mass of rock, water and oil together, while a dry-basis number divides it by the solids alone. The same cuttings sample therefore reads lower on the wet basis than on the dry basis, and every comparison between jurisdictions starts by naming the basis of each number.

Discharge limits for oil on cuttings by jurisdiction#

Oil on cuttings discharge limits differ by jurisdiction and by basis: grams of base fluid per 100 g of wet cuttings in US federal waters, percent or grams per kilogram of dry cuttings in the OSPAR area and Norway.

The table below compares the limit for water-based and non-aqueous cuttings in each jurisdiction, with the instrument, section and date and the basis of each number.

The US retention limit is a weighted average over all non-aqueous well sections, never a cap on a single sample. Before any cuttings count, the base fluid passes three stock tests against the C16-C18 internal olefin reference: a polycyclic aromatic hydrocarbon (PAH) mass ratio of at most 1 x 10^-5 as phenanthrene, and sediment toxicity and biodegradation rate ratios of at most 1.0 (40 CFR 435.13). OSPAR Decision 2000/3 applies across the North-East Atlantic, and Norway adds a national limit that also covers formation oil, so a Norwegian well answers to both instruments.

Coastal waters carry stricter discharge rules than the shelf. Section 435.43 bars discharge from coastal facilities except in Cook Inlet, Alaska, where non-aqueous cuttings need a technical exemption before the offshore limits apply. In the western Gulf, EPA Region 6 applies the offshore limits through general permit GMG290000 (88 FR 36316, 2023). Stock-limit test methods and the definitions behind each limit are set in the US offshore discharge rules of 40 CFR 435, Subpart A.

Wet basis and dry basis: comparing the limits#

A 1 % cap on dry cuttings allows at most 1 g of oil per 100 g of wet cuttings, so the US internal olefin limit is at least 6.9 times as permissive (calculated).

Wet mass is at least the dry solids plus the oil. One gram of oil on 100 g of dry solids therefore becomes 0.99 g per 100 g of wet cuttings, and less still when the cuttings also hold water (calculated). Dividing the US internal olefin limit by that ceiling of 1 g gives the factor of 6.9, and the ester limit gives a factor of 9.4 (calculated).

Norway's 10 g/kg dry mass equals 1.0 % by mass of dry cuttings (calculated, 10 divided by 1,000), the same level as the OSPAR cap. The two European limits still stand under two instruments: OSPAR Decision 2000/3 for oil-based cuttings across the convention area, and Activities Regulations s.68 for base fluid or formation oil on Norwegian cuttings. A table that sets US and European numbers side by side compares a wet-basis ceiling with dry-basis ceilings, and the conversion above is the step that makes them comparable.

Retort and sheen checks on cuttings at the rig#

US retention on cuttings is measured by EPA Method 1674, a retort procedure in Appendix 7 to 40 CFR 435 Subpart A that is derived from API RP 13B-2.

The Method 1674 retort must reach at least 930 degF (500 degC), the test must start no more than 2 h after sampling, and the mass balance must close within 5 %. The rules set the frequency as well: a retort once a day over the first 0.33 of the footage planned with non-aqueous fluid.

Mud retort analysis on whole mud splits the circulating fluid into water, oil and solids. That mud retort analysis of the mud and Method 1674 on cuttings are separate procedures with separate tolerances, and neither tolerance transfers to the other.

Free oil and formation oil are checked by two further EPA methods, the static sheen test (Method 1617) and gas chromatography with mass spectrometry (GC/MS, Method 1655), and either finding stops the discharge whatever the retort shows.

Which Fluid Choices and Additives Change What the Cuttings Carry?#

The base fluid, the weighting agent and the shale inhibitor set what drill cuttings carry: internal olefin and ester base fluids can meet the US cuttings limits, while diesel and mineral oil cannot (40 CFR 435.13).

Drilling fluid additives change cuttings by class rather than by product. The choice among drilling fluid additives for a well with offshore discharge starts from the base fluid, then the barite lot, then the inhibitor package. In the North-East Atlantic, barite and barium sulfate are on the PLONOR list (OSPAR Agreement 2013-06, Update 2026), and encapsulating polymers keep cuttings intact so that solids control removes them whole.

Send one specification to independent suppliers of drilling fluid materials. request supplier quotes

The table below compares eight materials and systems by what each does to the cuttings and the rule that applies.

Material grades and lots vary by supplier; compare additive suppliers by material and region.

How Are Drill Cuttings Treated Before Discharge or Disposal?#

Drill cuttings treatment runs in two steps: solids control and cuttings dryers at the rig return free fluid to the mud system, and thermal treatment then drives off the remaining oil until the cuttings meet a limit.

The first step recovers base fluid for reuse in the mud and lowers the retention that the US limit measures. The second step serves the dry-basis limits of the OSPAR area and the shore facilities that receive oil-based cuttings.

Shakers, fines removal and cuttings dryers#

Shakers alone left a long-term average of 10.2 % base fluid on cuttings in the data behind the 2001 US rule, and adding a cuttings dryer and fines removal unit cut it to 3.82 % (EPA, 66 FR 6850, 2001).

The table below compares the solids-control configurations in the 2001 rule record by long-term average retention, on the same wet-cuttings basis as the US limit.

Option 2 leaves 62.5 % less base fluid on cuttings than shakers alone (calculated from the table).

Cuttings dryers in the rule record include the vertical or horizontal centrifuge, the squeeze press mud recovery unit and the high-G linear shaker, named here as equipment types only. EPA estimated that the 2001 rule cuts discharges by 118 million lb (about 53,500 t) a year (66 FR 6850, 2001).

Thermal treatment: TCC and thermal desorption units#

Thermomechanical cuttings cleaning (TCC) heats oil-based cuttings to 482 to 572 degF (250 to 300 degC) by friction in a hammermill, without external heat (Norwegian Oil and Gas Association report, 2014).

Field TCC units in that report left an average of 0.03 % oil on the treated cuttings, equal to 0.3 g/kg dry mass, with a maximum of 0.08 % (0.8 g/kg dry mass). Both values sit far below the dry-basis limits of the OSPAR area and Norway.

Regulators still read the same result differently. Discharge of TCC-treated cuttings has been approved on the UK continental shelf since 2003, while Norway, as of 2014, approved no treatment technology for discharging oil-based cuttings and shipped them to land instead (Norwegian Oil and Gas Association report, 2014).

Thermal desorption uses external heat. In a pilot with a twin-screw unit heated by electromagnetic induction and a throughput of 250 L/h (about 1.57 bbl/h), cuttings tested between 572 and 1,022 degF (300 and 550 degC) reached below 1 % total petroleum hydrocarbons (TPH) at 842 degF (450 degC), about 95 % oil removal (Zhang and Yao, J. Petrol. Explor. Prod. Technol., 2018). At 1,022 degF (550 degC) with a 12 min residence time, the residue fell to 0.3 % TPH in the same study.

Where Do Drill Cuttings Go? Disposal Routes Compared#

Drill cuttings disposal follows one of four routes: discharge at sea after treatment, reinjection into a deep formation, skip and ship to a shore facility, or treatment and disposal on land under state or provincial rules.

The table below compares the four routes by where each is used and what limits it.

Drill cuttings management chooses the route well by well, from the base fluid, the location and the treatment the rig carries.

Offshore discharge and cuttings piles#

Offshore discharge is the route for water-based cuttings and for treated non-aqueous cuttings within the limit, and in the OSPAR area 11 wells drilled with organic-phase fluid discharged treated cuttings in 2019 (OSPAR QSR 2023).

That count has ranged from 7 to 20 wells a year, and in each case the cuttings were treated to below the OSPAR oil-on-cuttings cap before discharge (OSPAR QSR 2023).

Legacy cuttings piles on the seabed fall under OSPAR rules through Recommendation 2006/5, a management regime for offshore cuttings piles. In a 2009 assessment, all 174 UK piles fell below its thresholds. Two further agreements complete the OSPAR rules for cuttings: Agreement 2002-08 on the best environmental option for cuttings residue contaminated with organic-phase fluid, and Agreement 2017-03 on sampling and analysis of cuttings piles.

Cuttings reinjection#

Cuttings reinjection grinds cuttings into a slurry and pumps it into a deep formation, and one Piceance Basin pilot in Colorado injected over 42,000 bbl (6,677 m3) between December 2007 and March 2008 (Intermountain Oil and Gas BMP Project).

The injection target was a lost-circulation zone of the Wasatch G formation at about 5,500 ft (1,676 m) true vertical depth, a formation that already took fluid from the well. The pilot volume breaks down into 9,500 bbl (1,510 m3) of cuttings slurry, 31,000 bbl (4,929 m3) of produced-water flushes and 1,700 bbl (270 m3) of drilling fluid. Flush water therefore made up more than three times the slurry volume (calculated from these figures), so a reinjection program plans water supply and pump time for the flushes as well as for the cuttings.

Skip and ship, cuttings boxes and disposal on land#

Skip and ship moves cuttings in closed containers, the cuttings boxes or skips, from the rig to a shore facility, and it is the route for cuttings that cannot meet a discharge limit.

On water-well and small rigs, the same container logic applies on land. The Driller (2015) describes 3 yd3 (2.29 m3) tip bins feeding 20 yd3 (15.3 m3) watertight roll-offs that are filled about halfway, and spent mud follows the same containers into drilling waste management for solidification and disposal.

Onshore, federal rules close the water routes. Section 435.32 bars discharge of drilling muds and cuttings from onshore wells to navigable waters, and Subpart E bars it for agricultural and wildlife water use west of the 98th meridian. Shale and tight wells may not send drilling muds or cuttings to publicly owned treatment works (40 CFR 435.33 and 435.34; 81 FR 41845, 2016).

States and provinces set the land-treatment limits. Louisiana Statewide Order 29-B and Alberta Energy Regulator Directive 050 are two such instruments, each with its own soil, salt and oil limits for spreading or burying cuttings.

What Goes Wrong in Cuttings Handling and Discharge?#

Cuttings problems show up as failed checks: a sheen over more than half the test surface stops the discharge, a retort result above the retention limit raises the well average, and formation oil bars the cuttings from the sea.

Free oil is the fastest of these failures to detect. A static sheen test on 15 g of wet cuttings shows it under EPA Method 1617, and a sheen or slick over more than half the surface stops the discharge (40 CFR 435, Subpart A).

The table below lists five cuttings problems with the check that shows each, its consequence and the fluid-side response.

Each failed check costs either the discharge route or the well average. A retention average is built section by section, so one high section raises the result for the whole well, and the dryer and fines removal settings of the next section carry the correction.

How Are Cuttings Treatment and Disposal Services Sourced?#

Cuttings treatment and disposal are sourced as a service scope rather than a product: the operator defines the fluid, hole sections, applicable limit and route, then asks for dryers, thermal units, injection or haulage.

The scope follows the route. Offshore discharge needs rig-side dryers and retort reporting; skip and ship needs containers, vessel space and a receiving facility; reinjection needs a slurry unit and an injection well; land disposal needs haulage and a permitted site.

Retention reports and the fluid program belong to mud engineering. Rig-side mud engineering services cover the fluid half of the scope, while treatment and haulage contractors cover the cuttings once they leave the shakers.

The five items a cuttings service request states are listed below.

• Fluid system: water-based, oil-based or synthetic-based mud.
• Base fluid: internal olefin, ester, mineral oil or diesel.
• Hole sections: sizes and planned footage of each section.
• Jurisdiction and permit: the instrument and limit that apply.
• Route: offshore discharge, reinjection, skip and ship or land disposal.

How Do Drill Cuttings Relate to Spent Mud and the Rest of the Waste Stream?#

Drill cuttings are one stream of drilling waste: they leave the hole continuously while drilling, whereas spent mud, wash water and pit contents arise at section ends and at the end of the well.

Cuttings are also the stream that carries the base fluid out of the mud system day by day. The wider picture of drilling fluids and the environment adds toxicity testing and chemical notification to the cuttings rules. Drilling into metal with cutting oil is metalworking, not drill cuttings.

Are drill cuttings hazardous waste?#

No, not under the US federal hazardous waste rules: drilling fluids and other exploration and production wastes are excluded from hazardous waste by 40 CFR 261.4(b)(5), and state rules still apply.

EPA lists drilling fluids and cuttings among the drilling-stage wastes managed under Subtitle D, and its review found revisions to those rules "not necessary at this time" (EPA, page updated 2026-03-02).

How much cuttings does a well make?#

A 12-1/4 in hole drilled in gauge produces about 145.8 bbl (23.2 m3) of rock per 1,000 ft (304.8 m) before the broken cuttings bulk up (calculated, IADC hole capacity).

Rock volume grows with the square of the bit diameter, the same hole-capacity arithmetic that sets mud volume. The mud volume calculator applies it to any hole size and length.

The table below lists the in-gauge rock volume per 1,000 ft (304.8 m) for three hole sizes.