Engineering Standards Center
The standards behind the work.
The API, ISO and regulatory references that govern solids control, drilling fluids and drilling-waste management — with field-validated performance benchmarks, equipment acceptance criteria and commissioning checklists. Every entry cites its source so you can verify and quote it.
44 standards & references · 99 cited sources · 10 sectionsAPI Standards
The American Petroleum Institute (API) recommended practices and specifications that govern drilling-fluid testing, materials and solids-control equipment. These are the working reference for the whole circuit.
Drilling Fluids Materials
Physical properties and test procedures for materials used in drilling fluids — barite, hematite, bentonite, OCMA-grade bentonite, attapulgite, sepiolite, CMC (LVT/HVT), starch, PAC (LV/HV) and drilling-grade xanthan gum.
- Barite (API grade) must have a specific gravity of 4.20 or higher; 'Barite 4.1' is a separate lower-density grade at SG ≥ 4.10.
- Sets limits on soluble alkaline-earth metals, residue and moisture for each material.
- Bentonite is specified by yield, rheology, filtrate and residue requirements.
- Carries the API Monogram program for manufacturer certification.
In the fieldUse to write barite/bentonite acceptance criteria into a mud-supply contract and to verify what arrives at the rig or mud plant.
Field Testing Water-Based Drilling Fluids
Standard rig-site procedures for testing water-based mud: density (mud weight), viscosity and gel strength, filtration, water/oil/solids content, sand content, methylene-blue capacity (MBT), pH, alkalinity and lime, chloride, total hardness, and low-gravity-solids / weighting-material concentrations.
- Defines the 600/300 rpm viscometer readings used to calculate PV and YP.
- Defines the API filter-press fluid-loss test (30 min, 100 psi) and the HTHP filtration test.
- Defines the retort method for oil/water/solids and the sand-content test (>74 µm).
- MBT quantifies reactive clay (cation-exchange) loading in the mud.
In the fieldThe reference every mud check on a water-based well is run against — cite it when standardising the morning mud report.
Field Testing Non-Aqueous (Oil-Based) Drilling Fluids
Rig-site procedures for oil-based and synthetic-based mud: density, viscosity and gel strength, filtration (HTHP), oil/water/solids by retort, electrical stability (ES), alkalinity, chloride and calcium, and lime content.
- Electrical-stability (ES) test is unique to invert-emulsion mud — it tracks emulsion strength.
- Retort separates the oil, water and solids fractions to give the oil/water ratio (OWR).
- The retort method here is the basis of EPA Method 1674 for base fluid retained on cuttings.
- HTHP filtration characterises filter cake under downhole-like conditions.
In the fieldThe companion to 13B-1 for invert-emulsion systems; ES and OWR trends are your early warning on an OBM/SBM system.
Drilling-Fluid Processing Systems Evaluation
A standard procedure for assessing and modifying the performance of the solids-control equipment system in the field. It is a system-level evaluation method, not a way to compare individual pieces of equipment.
- Gives a structured way to audit a complete solids-control train against the mud and the flow it must handle.
- Underpins a proper rig solids-control evaluation: mass balance, equipment loading, and where fluid is lost.
- Note: the screen-labelling procedure many people call '13C' is the separate shaker-screen standard now aligned to ISO 13501 (see Screen Labelling below).
- Drilled solids are processed in series — each stage depends on the one before it.
In the fieldThe backbone of a remote or on-site rig evaluation — this is the method behind 'measured, not guessed'.
Shale-Shaker Screen Testing & Labelling
A physical testing and labelling procedure for shale-shaker screens. Two tests are defined: the D100 cut point and conductance. Every compliant screen must carry a permanent label showing the API screen number and conductance in kD/mm.
- D100 cut point = the largest particle that passes the screen, determined with a Ro-Tap and aluminium-oxide against calibrated ASTM E-11 sieves.
- Screens with a cut point in the same band share an API number — e.g. >165 µm and <196 µm are all API 80 — so same-API screens are interchangeable across vendors.
- Conductance (kD/mm) describes how freely fluid passes; higher conductance moves more flow at the same cut.
- The API number describes separation potential only — not field performance, which also depends on fluid, shaker design and ROP.
- Replaces API RP 13E, which used optical opening measurement and gave inconsistent vendor labels.
In the fieldSpecify screens by API number + conductance, not raw mesh — the only way to compare screens fairly and reorder correctly.
Rheology & Hydraulics of Oil-Well Drilling Fluids
Models and methods relating drilling-fluid rheology to flow behaviour, annular pressure loss, hole cleaning and equivalent circulating density (ECD). The basis for the hydraulics program in well planning.
- Provides the rheological models (Bingham plastic, power-law, Herschel-Bulkley) used to predict pressure loss.
- Links low-shear-rate viscosity and gels to hole cleaning and barite-sag tendency.
- ECD prediction from this RP defines the drilling window between pore and fracture pressure.
- Solids loading raises PV and ECD — a direct tie between solids control and hydraulics.
In the fieldCite when explaining why fine-solids build-up (poor solids control) raises ECD and narrows the drilling window.
Laboratory Testing of Drilling Fluids
Laboratory procedures for testing both drilling-fluid materials and the physical, chemical and performance properties of water-based and non-aqueous fluids, including the base/make-up fluid. The lab counterpart to the 13B field tests.
- Stresses that agitation history and test temperature strongly affect measured properties — control both for repeatable results.
- Used for product qualification and pre-spud formulation, not as a rig-floor control manual.
- Defers barite trace-metal testing (mercury, cadmium, arsenic) to API RP 13K.
- Equivalent to ISO 10416 internationally.
In the fieldThe reference for any lab-based mud or additive qualification before it reaches the rig.
Completion Fluids, Barite Analysis, Technologist Training & Completion-Fluid Rheology
The supporting members of the API 13 series: 13J (testing of heavy brines / completion fluids), 13K (chemical analysis of barite, including mercury, cadmium and arsenic), 13L (training and qualification of drilling-fluid technologists), and 13M (measurement of viscous properties of completion fluids).
- 13K is where barite trace-heavy-metal limits (Hg, Cd, As) are actually tested — important for HSE and discharge.
- 13L sets the competency framework for mud engineers / drilling-fluid technologists.
- 13J covers heavy clear brines used in completions (density, crystallisation point).
- 13M (part of the ISO 13503 family) standardises completion-fluid viscosity measurement.
In the fieldCite 13K for barite heavy-metal acceptance, and 13L when building a mud-engineer competency program.
Shale-Shaker Screen Cloth Designation (Superseded)
The earlier screen-designation practice based on optical (microscope) measurement of the screen opening. Different manufacturers used their own methods, producing inconsistent labels.
- Historically used D50 as the screen cut point; the current 13C/ISO 13501 method uses D100.
- Replaced because optical opening measurement did not give comparable results between vendors.
- You may still see legacy 13E part numbers — re-specify them to a 13C API number before reordering.
In the fieldContext for old screen part numbers — convert them to current API-number designations.
ISO References
The international (ISO) equivalents of the API drilling-fluid standards, plus the environmental-management framework. Many API RPs are published as identical ISO standards, so an ISO reference and its API twin are the same procedure.
Drilling-Fluid Materials
International specification for drilling-fluid materials — barite, hematite, bentonite, clays, cellulose polymers (CMC/PAC), starch and xanthan gum — with the same physical-property and test requirements as API Spec 13A.
- Barite SG ≥ 4.2 (and the separate 'barite 4.1' grade at ≥ 4.1), matching API 13A.
- Same monogram-style conformity for manufacturers internationally.
- References ISO 6780 for pallet handling of packaged material.
In the fieldUse the ISO 13500 citation where a client or regulator works to ISO rather than API.
Field Testing of Drilling Fluids
International procedures for field testing of water-based (Part 1) and non-aqueous (Part 2) drilling fluids — density, rheology, gel strength, filtration, solids/oil/water content, sand, MBT, pH, alkalinity, chloride and hardness.
- ISO 10414-1 is identical to API RP 13B-1; ISO 10414-2 to API RP 13B-2.
- Annexes cover glassware and instrument calibration so results are repeatable rig-to-rig.
- USC units are given in brackets alongside SI for field use.
In the fieldThe ISO citation for the morning mud report on internationally operated rigs.
Laboratory Testing of Drilling Fluids
Procedures for laboratory testing of both drilling-fluid materials and drilling-fluid physical, chemical and performance properties — the lab counterpart to the rig-site field tests.
- Used for product qualification and for pre-spud mud formulation work.
- Referenced alongside ISO 10414 and API RP 13D for a complete testing chain.
- Backs material acceptance under ISO 13500 / API 13A.
In the fieldCite for any lab-based mud qualification or additive evaluation.
Shaker Screens & System Evaluation
ISO 13501 is the screen testing and labelling procedure (D100 cut point + conductance). ISO 13502 is the solids-control system performance-evaluation procedure.
- ISO 13501 = the international form of the shaker-screen labelling standard.
- ISO 13502 = the international form of the system-evaluation method.
- Both let an evaluation be written to ISO references where required.
In the fieldThe ISO citations to pair with API RP 13C in a tender or audit document.
Environmental Management Systems
The framework for an environmental management system (EMS): identifying significant environmental aspects, setting reduction targets, and putting operational controls on waste — including segregation, labelling, documented transport and licensed disposal of hazardous waste.
- Embeds the waste hierarchy (reduce, reuse, recover, treat, dispose) into operations.
- Requires documented procedures for transporting and disposing of hazardous waste through licensed contractors.
- Drives lower drilling-waste volumes and traceable disposal records — directly relevant to cuttings handling.
In the fieldThe management-system backbone for a drilling-waste plan and for demonstrating duty of care on disposal.
Mechanical Equipment Standards
The design, construction and testing standards for the rotating and pressure equipment in a solids-control package — the centrifugal pumps that feed the cyclones, the decanter centrifuge, and the mechanical-integrity practices that keep them running.
Centrifugal Pumps for Petroleum Service
The oil-and-gas standard for centrifugal pump design, construction, testing, rotor dynamics and metallurgy — for pumps handling hydrocarbons, corrosive fluids and high temperature/pressure. Classifies pumps as overhung, between-bearings or vertically suspended.
- API 610 governs construction and ruggedness (pressure/temperature capability), where ANSI/ASME B73.1 governs dimensions for general-service pumps.
- API 685 is the sealless (magnetic-drive/canned-motor) equivalent of API 610.
- ANSI/ASME B73.1 horizontal end-suction pumps are the common choice for lower-duty mud-transfer service.
- ANSI/HI (Hydraulic Institute) standards cover rotodynamic pump design, application and IOM manuals.
In the fieldSpecify API 610 for critical/high-duty pumps; B73.1 is acceptable for general mud-transfer duty — match the standard to the service.
Decanter Centrifuge Build & Quality
Solids-control decanter centrifuges are built under manufacturer quality-management systems (ISO 9001) rather than a single product standard. Key build features: bowl length-to-diameter ratio, gearbox torque rating, and variable-frequency (VFD/PLC) control.
- A bowl length/diameter ratio around 3.2 (e.g. ~22 in bowl, ~71 in length) is considered good for big-bowl drilling-mud units — longer settling zone, finer cut.
- High-torque gearbox plus a back-drive motor sets the conveyor differential and torque capacity.
- VFD with PLC control allows bowl speed and differential to be tuned to the duty (barite recovery vs fine-solids removal).
- Position in the train: centrifuge follows shakers, mud cleaners, degasser and hydrocyclones.
In the fieldWhen accepting a centrifuge, check bowl L/D, gearbox torque rating, VFD/PLC control and the QA certification — not just bowl speed.
Drilling-Waste Management Equipment
The equipment that treats what the solids-control circuit removes — drying the cuttings, recovering the fluid, dewatering the liquid phase and conditioning the waste for disposal or re-injection. These are the units that turn a discharge problem into a compliance and cost win.
High-G Screen-Bowl Cuttings Dryer
A vertical screen-bowl centrifuge that spins oil/synthetic-based cuttings at high speed to fling off the adhering fluid, recovering base oil and cutting the oil-on-cuttings before disposal. The primary fluid-recovery unit in an OBM/SBM waste circuit.
- Typical duty: ~420 G at ~900 RPM (range across makers ~300–900 G); processes roughly 40–50 tons/hr.
- Reduces oil-on-cuttings (OOC) to as low as ~5% by dry weight — moving cuttings toward discharge or lower-cost disposal.
- Recovered base fluid returns to the active mud system; the liquid effluent usually goes to a high-speed decanter centrifuge to drop fine solids before reuse.
- Tungsten-carbide hard-faced flights (hard-faced to ~HRC 65) resist abrasion and hold the scroll-to-bowl gap.
- Often VFD-driven; fed by screw conveyor or vacuum transfer from the shakers.
In the fieldThe first treatment stage for OBM/SBM cuttings — get OOC down here before the cuttings ever reach a dryer or skip.
Indirect Thermal Treatment of Oily Cuttings
A thermal unit that heats oil-contaminated cuttings to drive off and recover the hydrocarbon as vapour, then condenses it — separating the waste into oil, water and clean solids. The deepest-cleaning step for OBM/SBM cuttings.
- Indirect (no flame contact) thermal desorption drives residual oil content in treated solids to below ~0.3% (typically <1% generally).
- Separates cuttings into three reusable/disposable streams: recovered base oil, water, and clean solids.
- Recovered base oil is unchanged and can be returned to the mud system at source; cleaned solids and water are often below environmental discharge limits.
- Integrated systems add pyrolysis-gas cooling, purification and combustion plus electric control.
- The predominant onshore route for oil-based cuttings in regions like the Norwegian Continental Shelf.
In the fieldWhere OOC must reach the lowest levels (discharge or beneficial reuse), TDU is the cleaning step after the dryer.
Chemically-Enhanced Liquid-Phase Treatment
Treats the liquid effluent and fine-solids slurry from the waste circuit by chemical coagulation and flocculation, separating it into a disposable solids cake and clarified water that can meet discharge requirements.
- An inorganic acidic coagulant conditions the slurry to allow settling and thickening; an organic polyacrylamide flocculant then aggregates the fine solids.
- Produces solids of less than ~50% moisture content plus clarified water.
- Clarified water may pass a COD-reduction step (carbon adsorption or reverse osmosis) to meet discharge limits.
- The treated cake can be an environmentally compatible material meeting leachate limits for landfill.
- Often paired with a high-speed centrifuge for the fine-solids removal stage.
In the fieldCloses the water loop on a waste system — recover/clarify water and produce a stackable, disposable cake.
Slurrification & Down-hole Disposal
A zero-surface-discharge route: cuttings are ground into a pumpable slurry and injected under fracture pressure into a dedicated disposal formation. Common offshore where surface storage is limited.
- Cuttings are collected from the solids-control equipment and fed to a slurrification unit, which grinds them with seawater/fluid into small particles.
- The slurry is conditioned in a holding tank (rheology adjusted) to a 'conditioned slurry', then pumped into the formation by creating fractures under high pressure.
- Requires one or more dedicated disposal wells; fracture modelling predicts the disposal extent and capacity.
- Grinding pumps on a CRI skid do the size reduction; injection may use a dedicated well or the annulus of the well being drilled.
- Eliminates surface cuttings handling but adds well-integrity and containment-modelling obligations.
In the fieldThe offshore answer when discharge is banned and skip-and-ship is impractical — but it needs a qualified disposal well and modelling.
Cuttings Transfer & Defluidizing
Augers that move cuttings between the shakers, dryer and skips without open handling, and screw-press variants that squeeze fluid out of the cuttings by compaction.
- Screw (auger) conveyors collect cuttings from the primary solids-control equipment and feed the vertical cuttings dryer — an enclosed alternative to belts or buckets.
- A defluidizing screw press uses a perforated strainer and a compacting screw to separate fluid from cuttings by compaction at a controlled rate.
- Enclosed conveyance reduces spillage, dust and the volume/handling problems of adding wash water.
- Conveyors are central to keeping a closed, low-exposure cuttings-handling line on deck.
In the fieldUse enclosed augers/press conveyance to keep the cuttings line closed — less dust, less spill, less manual handling.
Containment, Skip-and-Ship & Vacuum Transfer
Containment and transport of cuttings to shore for treatment/disposal — the 'skip-and-ship' route — and the bulk/vacuum-transfer systems that move cuttings around the rig in a closed line.
- Skip-and-ship: oil-based cuttings are contained in skips of about 10-ton capacity, crane-loaded onto supply boats — a common solution on the Norwegian Continental Shelf.
- Crane lifting of loaded skips is a recognised difficult/hazardous operation — plan it as a controlled lift (see Lifting standards).
- Bulk/vacuum-transfer systems move cuttings in a closed line, avoiding open conveyors and added wash water.
- Choice between skip-and-ship, bulk transfer and offshore treatment is increasingly driven by emissions as well as cost (DNV-assessed).
In the fieldWhere treatment isn't available offshore, contain and ship — but cost the crane lifts and emissions, not just the freight.
Secondary Screening & Biological Treatment
Supporting treatment routes: drying shakers as a secondary fine-screening stage on cuttings, and bioremediation as an eco-friendly biological route for low-concentration oily cuttings.
- Drying shakers give a secondary screening/drying pass on cuttings ahead of or alongside the vertical dryer.
- Bioremediation uses microorganisms to break down hydrocarbons — effective and low-impact for low-concentration OBM cuttings.
- For water-based cuttings, centrifugation or filtration recovers reusable fluid and leaves disposable solids.
- Mechanical dewatering followed by chemical stabilization is used where regulations are strict.
- Route selection is framed by standards like the OSPAR Convention and national rules.
In the fieldMatch the route to the contamination level: bioremediation for light OBM residue, dewatering+stabilization where limits are tight.
Electrical & Hazardous-Area Standards
Solids-control equipment sits in classified areas where flammable gas can be present, so its motors, starters and lighting must carry the right explosion-protection rating. These standards decide what equipment is legal where on the rig.
Explosive Atmospheres — Equipment & Area Classification
The international framework for electrical (and, via related parts, non-electrical) equipment in explosive gas atmospheres. IEC 60079-10-1 classifies gas areas into zones; IEC 60079-0 sets general equipment marking.
- Gas zones: Zone 0 = explosive atmosphere present continuously/long periods; Zone 1 = likely in normal operation (e.g. near pumps/valves); Zone 2 = unlikely and short-lived if it occurs.
- Equipment Protection Level (EPL) must match the zone: Ga→Zone 0, Gb→Zone 1, Gc→Zone 2.
- A full marking looks like: II 2G Ex db IIC T4 Gb — group, category, Ex, protection type, gas group, temperature class, EPL.
- Temperature (T) class caps the equipment surface temperature below the gas auto-ignition temperature (T1…T6).
- Dust atmospheres use Zones 20/21/22 (IEC 60079-10-2).
In the fieldConfirm every motor, starter and light on the solids-control package carries an Ex rating valid for the zone it sits in.
Equipment Certification Schemes
The certification schemes that prove a piece of equipment meets the IEC 60079 requirements. ATEX is the EU legal route (covers electrical and non-electrical equipment); IECEx is the international scheme (electrical equipment) that lets one certificate be accepted across countries.
- ATEX categories map to zones: Category 1 → Zone 0/20, Category 2 → Zone 1/21, Category 3 → Zone 2/22 (lower number = higher protection).
- ATEX covers both electrical and non-electrical equipment; IECEx covers electrical equipment but is accepted globally without re-testing.
- Both align technically with IEC 60079, and markings are often combined on one nameplate.
- Mining equipment uses Group I (categories M1/M2); surface oil-and-gas uses Group II.
In the fieldOn internationally moved rigs, IECEx avoids re-certifying per country; in the EU, ATEX is the legal requirement.
North American Hazardous-Location System
The North American system for classifying hazardous locations, used on US rigs. Article 500 is the Class/Division system; Articles 505/506 are the Zone system that harmonises with IEC.
- Class I = flammable gases/vapours. Division 1 ≈ IEC Zone 0+1; Division 2 ≈ IEC Zone 2.
- Gas groups A–D (NEC) correspond to IEC gas groups; equipment must match the group present.
- US upstream rigs commonly require Class I, Division 2 certified equipment (with intrinsic-safety where needed).
- The NEC Zone system (505/506) was added to align with the international IEC zones.
In the fieldOn US-flagged or US-operated rigs, equipment is usually specified to NEC Class I, Division 1/2 rather than IEC zones.
Discharge & Environmental Regulations
The regulatory limits that decide what can be discharged and how cuttings must be treated. Numbers are from the U.S. EPA effluent guidelines (40 CFR Part 435); other regions (OSPAR in the North-East Atlantic, regional authorities in the GCC) apply their own, often stricter, limits.
Offshore Subcategory (US EPA)
Federal effluent-limitation guidelines for offshore oil-and-gas discharges — produced water, drilling fluids and drill cuttings.
- Produced-water oil & grease limit: 72 mg/L daily maximum, 48 mg/L 30-day average.
- No discharge of free oil — tested by the Static Sheen Test (EPA Method 1617); a sheen on the water fails.
- Discharge of oil-based (diesel/mineral-oil) mud and its cuttings is prohibited offshore.
- Synthetic-based-fluid cuttings are controlled by base-fluid-retained-on-cuttings limits (EPA Method 1674, derived from API RP 13B-2 retort) plus sediment-toxicity and biodegradation tests.
In the fieldThe hard limits an offshore discharge plan and a cuttings-treatment target must meet in US waters.
Onshore & Coastal Subcategories (US EPA)
Effluent limits for onshore (Subpart C) and coastal (Subpart D) operations.
- Onshore baseline: no discharge of drilling muds, cuttings, produced water or produced sand to navigable waters.
- Coastal baseline is zero-discharge, with narrow technical exemptions (e.g. certain Cook Inlet SBF/EMO cuttings).
- Drives onshore reliance on cuttings re-injection, treatment and licensed disposal.
In the fieldSets the onshore/coastal disposal route — typically containment, treatment and haul-off rather than discharge.
North-East Atlantic Offshore Discharge Regime
The regional regime protecting the marine environment of the North-East Atlantic (North Sea and beyond). It governs the discharge of drilling fluids, organic-phase-fluid (OPF) cuttings, produced water and offshore chemicals.
- OPF-contaminated cuttings: discharge prohibited above 1% oil by weight on dry cuttings (since 2001) — the key cuttings-cleaning target offshore in the OSPAR area.
- Discharge of whole organic-phase fluids is prohibited; diesel-based fluids banned since 1987; OPF cuttings discharge above the limit only allowed in rare force-majeure cases.
- Produced-water performance standard: dispersed-oil upper limit of 30 mg/L (per OSPAR reference method).
- Harmonised Mandatory Control System (HMCS) governs offshore chemicals (HOCNF notification; PLONOR list; substitution candidates).
- Recommendation 2006/5 manages legacy offshore cuttings piles.
In the fieldIn the North Sea / OSPAR area, clean OPF cuttings below 1% OOC before any discharge, and screen chemicals against the HMCS/PLONOR list.
- OPF cuttings >1% by weight prohibited since 2001; whole-OPF discharge & diesel ban — OSPAR (Response assessment) ↗
- Cuttings cleaned below 1% by weight before discharge; HMCS & PLONOR — OSPAR (Impacts of offshore O&G) ↗
- Produced-water dispersed-oil 30 mg/L; HMCS; disused-installation ban — OSPAR Assessments ↗
- 1% mineral-oil-on-cuttings limit origin (PARCOM 92/2 → OSPAR); NADF discharge ended Jan 1997 — Oil & Gas Journal ↗
Reduce–Reuse–Recover–Dispose & GCC/National Limits
The over-arching principle that ranks waste options, plus the reality that regional and national authorities (including in the MENA/GCC region) set their own discharge and disposal limits — often referencing international good practice.
- Waste hierarchy (embedded in ISO 14001): prevent/reduce first, then reuse, then recover/recycle, then treat, and dispose only as the last resort.
- Applied to drilling waste: minimise solids generation, recover base fluid (dryer/TDU), recover water (dewatering), then dispose of inert solids.
- Regional/national limits vary widely; many jurisdictions reference IFC/World Bank EHS guidance where local numbers are absent.
- Operators must document the disposal route, transport and licensed-contractor chain (duty of care).
- Always confirm the specific limit with the local regulator — the EPA and OSPAR numbers here are reference points, not universal values.
In the fieldDesign the waste plan top-down the hierarchy — and confirm the actual numeric limits with the local authority for the country you're drilling in.
HSE & Occupational Standards
Solids-control and waste handling expose crews to dust, chemicals and lifting hazards. These are the health, safety and environmental standards that govern how the work is done safely — dust limits, radioactive scale, lifting, and the management framework around them.
Barite/Bentonite Dust Exposure Limits
Bulk barite and bentonite handling generates respirable crystalline silica and mineral dust — a chronic health hazard (silicosis). These standards set the airborne exposure limits and the control hierarchy.
- OSHA permissible exposure limit (PEL) for respirable crystalline silica: 50 µg/m³ as an 8-hour TWA; action level 25 µg/m³.
- NIOSH recommended exposure limit (REL): 50 µg/m³ (0.05 mg/m³); ACGIH TLV: 25 µg/m³ (0.025 mg/m³) for α-quartz.
- Control hierarchy: eliminate/substitute, then engineering controls (enclosed transfer, dust collection, water sprays), then respiratory protection.
- A written exposure-control plan and a designated competent person are required where exposure can reach the action level.
- Directly ties to mud-plant dust collection on barite/bentonite silos and transfer points.
In the fieldSet dust-collection and PPE requirements on bulk barite/bentonite handling against the 50 µg/m³ PEL — engineering controls first.
Naturally-Occurring Radioactive Material in Cuttings & Scale
Drill cuttings, scale and sludge can concentrate naturally-occurring radioactive material (NORM). Handling, monitoring and disposal of NORM-bearing waste is governed by international guidance and national regulation.
- NORM = radioactive material containing only naturally-occurring radionuclides, sometimes concentrated by the process.
- ICRP recommends a public dose limit of 1 mSv per year above natural background.
- A NORM management strategy needs monitoring (instrument choice matters), segregation, and records — refreshed when operations change.
- Regulations vary by country; plans must reflect where NORM deposits and all applicable national/international rules.
- Relevant to cuttings handling, tank cleaning and equipment decontamination.
In the fieldScreen cuttings and equipment for NORM where geology warrants it; manage and dispose of NORM-bearing waste under licensed, documented control.
Safe Handling of Equipment & Consumables
Moving screens, cyclone assemblies, centrifuges and bulk sacks involves mechanical lifting — a leading source of offshore incidents. IOGP Report 376 sets the recommended practice for safe lifting and hoisting, onshore and offshore.
- Applies to all mechanical lifting and hoisting, including associated transport and handling, across the operation's lifecycle.
- Emphasises planning, competent personnel, certified equipment and clear control of the lift.
- Dropped objects (from derricks, cranes, working at height) are a recurring offshore incident category — manage with DROPS-type surveys and tethering.
- Relevant to screen changes, centrifuge handling and bulk-bag movement around the shale-shaker house.
In the fieldPlan screen and centrifuge handling as controlled lifts with certified gear and a competent person — don't improvise around the shaker house.
Hydrogen Sulphide & Gas Control
Gas carried up in the mud — including toxic hydrogen sulphide (H₂S) — is a direct hazard at the shakers, degasser and possum belly. Solids-control layout and gas handling must keep crews safe.
- H₂S is an acute hazard that can incapacitate within seconds even at low concentration — the shaker area is a known exposure point.
- Entrained gas is removed by the vacuum degasser; a well-control gas influx must route to the mud-gas separator (MGS), not the degasser.
- Gas detection, ventilation and personal monitors are standard around the shale-shaker house.
- Ties directly to hazardous-area classification (gas zones) over the shakers and degasser.
In the fieldTreat the shaker/degasser area as a gas-exposure zone: detection, ventilation, correct degasser-vs-MGS routing and Ex-rated equipment.
Performance Benchmarks
Realistic, field-validated performance targets for each separation stage. Vendor 'best-case' numbers are usually finer than what a working rig sustains — these are the conservative benchmarks to design and audit against.
What each stage actually removes
The practical particle-size each stage removes in service — not laboratory best-case.
- Shale shaker: vendor claims below 74 µm exist, but assume ~100 µm as the practical field limit.
- Hydrocyclones (desander/desilter): practical removal down to ~25 µm (claims go lower).
- Decanter centrifuge: 2–10 µm depending on bowl speed, pond depth and feed rate; high-speed units reach the 2–5 µm range.
- Colloidal solids below ~2 µm cannot be removed mechanically — they must be managed by dilution and fluid design.
- Bentonite (<5 µm) is below centrifuge capability — another reason to control reactive solids upstream.
In the fieldSet honest expectations: don't expect the shaker to do the centrifuge's job, and don't blame equipment for sub-2-µm colloidal load.
Bowl speed & duty
The G-force ranges that separate barite recovery from fine-solids removal.
- Barite-recovery (middle-speed) duty: ~800 G — drops out barite (returned to mud) and passes the fines on.
- Fine-solids (high-speed) duty: up to ~2,000+ G — removes low-gravity fines, discards them.
- Barite recovery is typically run as a two-stage series: low-G first (recover barite), high-G second (discard fines).
- Barite is separated at roughly ≥10 µm; the second stage targets solids of ~20 µm and below.
- Staged centrifugation with chemical enhancement has driven LGS below ~4% on real systems.
In the fieldChoose and tune the centrifuge to the duty: recover barite OR remove fines — set bowl speed, pond and differential to match.
Primary-stage acceleration
The acceleration the screen delivers, which sets conveyance and the load handed to every downstream unit.
- G-force, set by stroke and speed, governs how aggressively cuttings convey and fluid passes the screen.
- An under-performing shaker floods the desanders, desilters and centrifuge — primary separation protects the whole train.
- Dual-motion shakers can switch between linear (high conveyance) and balanced-elliptical (gentler) modes to tune G to conditions.
- Optimising primary separation is a low-cost, high-impact lever on the entire operation.
In the fieldGet the shaker right first — it is the cheapest place to fix a solids-control problem.
Mud-quality benchmarks
The fluid-quality numbers that tell you solids control is working.
- Low-gravity solids (LGS) are commonly targeted below ~5–6% by volume on weighted systems; advanced staged processing has reached <4%.
- Rising plastic viscosity (PV) at constant mud weight is the classic signature of a solids-control problem.
- Sand content (>74 µm) should be kept low to protect pumps, bit nozzles and the circulating system.
- PV, YP and LGS are the standard tools used to score how well the mechanical equipment is performing.
In the fieldTrack LGS, PV and sand together — they are the scoreboard for the equipment.
Equipment Acceptance & Commissioning
Practical acceptance criteria and commissioning checks for receiving, installing and signing off solids-control equipment. These combine the standards above with field commissioning practice.
Receiving shaker screens
What to verify before a shaker screen is accepted and fitted.
- Each screen carries a permanent API RP 13C / ISO 13501 label showing API number and conductance (kD/mm).
- API number matches what was specified for the section — same-API screens are interchangeable across vendors.
- Non-blanked (open) area is as specified — it sets fluid capacity.
- No transit damage: panel flatness, bonding/hook-strip condition, mesh integrity.
- Re-specify any legacy 13E part numbers to a current API number before ordering.
In the fieldA one-page receiving check that stops the wrong or damaged screens going on the deck.
Receiving barite & bentonite
What to verify when bulk weighting and viscosifying materials arrive at the rig or mud plant.
- Barite specific gravity ≥ 4.20 (API grade) — or ≥ 4.10 if the 'barite 4.1' grade was ordered.
- Certificate of conformity to API 13A / ISO 13500 with the API Monogram where applicable.
- Bentonite meets yield/rheology/filtrate/residue requirements.
- Moisture and residue within spec; packaging intact; correct grade and quantity.
- Hold a retained sample for dispute resolution.
In the fieldProtects mud weight accuracy and chemical cost — reject off-spec barite before it goes in the silo.
Commissioning the solids-control package
Checks when a new or moved solids-control system is started up, before it goes into service.
- Confirm equipment order in series: shaker → desander → desilter → centrifuge; no stage bypassed.
- Feed each hydrocyclone bank at its design head (commonly ~75 ft / ~32 psi) from a correctly sized centrifugal pump; confirm underflow is a light spray, not a rope.
- Set sand trap unstirred; all other compartments agitated with no dead zones or settling beds.
- Confirm degasser handles entrained gas and that any well-control gas routes to the mud-gas separator (not the vacuum degasser).
- Centrifuge: verify bowl speed, pond depth and differential for the duty; confirm torque-protection set-point and test it.
- Run an API RP 13C (ISO 13502) system evaluation to baseline performance after start-up.
In the fieldA start-up sign-off that the train is plumbed, fed and tuned correctly before drilling depends on it.
Management Systems & Industry Frameworks
Above the individual equipment standards sit the management-system and industry frameworks that organise testing, waste and competency into an auditable system — the layer regulators and clients actually assess.
Drilling-Waste Management Technology Review
An industry-wide review of the wastes generated during well construction and operation — drill cuttings and associated fluids, onshore and offshore — and the technologies, methods and processes for managing them once generated.
- Covers waste types specific to drilling and those that present the biggest volume or environmental challenge.
- Frames the treatment options: containment, cuttings drying, dewatering, thermal treatment, re-injection and disposal.
- A neutral, producer-association reference for selecting a drilling-waste strategy.
- Complements the regulatory limits (e.g. EPA 40 CFR 435) with technology selection guidance.
In the fieldUse as the neutral technology map when choosing a cuttings-treatment route for a project.
Offshore Oil & Gas EHS Guidelines
Internationally referenced environmental, health and safety guidelines for offshore oil-and-gas development, widely used where national rules defer to international good practice (common in parts of the MENA/GCC region).
- Set discharge and waste-management expectations where local limits are absent or defer to international practice.
- Reference points include oil-on-cuttings and produced-water expectations and NORM handling.
- Used by lenders and operators as the baseline 'good international industry practice' (GIIP).
- Sits alongside OSPAR (North-East Atlantic) and national regulators (e.g. NOPSEMA, PSA Norway).
In the fieldCite where a project must demonstrate good international practice rather than a single national rulebook.
Quality Management Systems
The quality-management-system standard under which solids-control equipment manufacturers build and certify their products, and under which a service provider can run consistent, auditable processes.
- Drives consistent manufacturing and traceability of equipment such as centrifuges and pumps.
- Provides the documented-process backbone for inspection, acceptance and commissioning records.
- Pairs with ISO 14001 (environment) and ISO 45001 (occupational H&S) in an integrated management system.
- Often a tender prerequisite for equipment and service suppliers.
In the fieldLook for ISO 9001 certification on equipment supply, and use its discipline for your own acceptance/commissioning records.
From standard to shift.
The standards set the benchmark; the Failure Center and calculators turn them into action on the rig.
Common Failure Center → Q&A →This center summarises and points to published standards for engineering reference; it is not a substitute for the standards themselves. Standards bodies (API, ISO) revise their documents periodically — always work to the current edition and your local regulator's requirements. Regulatory limits shown (e.g. EPA 40 CFR 435) are examples; other jurisdictions, including OSPAR and GCC authorities, apply their own limits. Verify against the official source before relying on any figure.