1What is PSD?

Particle size distribution (PSD) is the full picture of what sizes of solids your mud is actually carrying — not one number, but the whole spread, from colloidal clay below 2 µm to coarse cuttings above 100 µm. Every screen cut, every cone, every centrifuge setting is a statement about where on this curve you are trying to cut. Read the PSD and the whole removal train stops being a row of machines and becomes one coherent system: each stage owns a size band, and what one stage misses, the next finer stage must catch — or dilution pays for it.

2D10, D50, D90, D100 explained

PSD is read at percentile points — the size below which a given fraction of the solids lies:

A useful habit: a tight distribution (D10 and D90 close together) is easy to cut cleanly; a wide one (fines and coarse together) means no single stage can do the job — you need the whole train.

3PSD vs the retort

PSD and the retort measure different things — they are complementary, not rivals. The retort (API RP 13B-1/13B-2) tells you how much solid is in the mud by volume (oil / water / total solids), and with mud weight you split that into barite and low-gravity solids. PSD tells you what size those solids are. One is quantity; the other is size.

You need both. The retort says “you have 18% solids and your LGS is climbing”; the PSD says “and they are fine — D50 has dropped to 20 µm, so the shaker can’t touch them; this is a centrifuge job.” Together they tell you not just that you have a solids problem, but which machine owns it.

4PSD vs dilution

Dilution is the most expensive lever on the rig, and PSD tells you when you are being forced to pull it. As the distribution shifts finer — D50 falling, the fine tail growing — mechanical removal gets harder: the solids are now below the cut point of every stage except the centrifuge. If the centrifuge can’t keep up, the only fast lever left is dilution, and the curve is telling you why your dilution rate is climbing.

The lesson: catch solids coarse and early, before they grind finer on every circulation and migrate down the curve into the colloidal range that only dilution and the centrifuge can chase. A rising fine tail is a dilution bill forming.

5PSD vs centrifuge performance

The centrifuge is the only stage that reaches the fine end of the curve — and PSD is how you prove it is working. A centrifuge that is genuinely cutting shifts the whole distribution coarser: it strips the fines, so the curve moves right and climbs later. No shift means no separation — the machine is running but not cutting (often poor recovery or wrong duty).

Compare a feed-vs-effluent PSD across the bowl and you have a direct, defensible measure of the cut point — see the decanting centrifuge guide for the duty settings that move it.

6Fine solids & LGS

Low-gravity solids (LGS) and the fine end of the PSD are the same enemy seen two ways. The fines that build at the D10 end are the drilled solids the equipment failed to catch while they were coarse — ground finer on every circulation until they disperse into colloidal clay (rising MBT) that no screen or cone can touch.

This is why PSD is a leading indicator: the fine tail starts growing before plastic viscosity and dilution confirm the problem. Watch the bottom of the curve and you catch the fines while the centrifuge can still take them — wait for the retort and you are already diluting.

7PSD interpretation guide

Reading a PSD in the field comes down to a few questions:

• Where is D50? Falling tour over tour = fines accumulating; the train is slipping.
• How fat is the fine tail (below D10)? A growing tail is a centrifuge / dilution problem forming.
• Is the coarse end (D90+) where it should be? Coarse solids surviving means a shaker bypass or a screen too coarse.
• Did the curve shift after the centrifuge? No shift = no separation.

Match the symptom to the stage: coarse survivors → shaker / desander; mid-range building → cones at low head; fine tail growing → centrifuge duty or hours.

8PSD case studies

Case — the dilution that PSD explained. A mud thickening with dilution climbing, retort solids “only” at 17%. The PSD showed D50 had fallen from 45 to 22 µm over the section with a fat fine tail — the solids were now below every cut except the centrifuge, which was running six hours a day. The fix was not chemistry: it was centrifuge hours, not dilution.

Case — the coarse survivors. Sand content low, yet abrasion wear high. The PSD’s coarse end (D90) sat well above the shaker cut — a holed panel was passing coarse solids the sand test, sampled elsewhere, never saw. The curve found what a single number hid.

Cases are illustrative of the method, not specific wells.

→Go deeper

1What drilling fluid does

Drilling fluid is the most multi-tasked material on the rig. Before anything else, it has to do several jobs at once:

• Carry cuttings out of the hole and suspend them when circulation stops.
• Control formation pressure — the hydrostatic column is the primary well-control barrier.
• Cool and lubricate the bit and string.
• Stabilise the wellbore — chemically and through a thin, sealing filter cake.
• Transmit hydraulic energy to the bit and any downhole tools.

Every property you measure is really a check on one of these jobs — and almost all of them are degraded by the same thing: drilled solids the system fails to remove. That is the thread that ties drilling fluids to solids control.

2Mud systems — WBM, OBM & synthetic

Mud systems fall into three broad families, chosen for the formation, the environment and the cost of disposal:

On non-aqueous fluids (OBM/SBM) the base fluid is expensive and the discharge is regulated, so every barrel lost on the cuttings is both a cost and a compliance issue — which is why the cuttings dryer and tight solids control matter most there.

3Key properties at a glance

A handful of properties tell you almost everything about the fluid’s health. These are the numbers on every daily mud report:

Notice how many of these point straight back at solids — PV, retort, MBT and sand are, in effect, solids-control scorecards in disguise. See the PSD Knowledge Center for the size dimension behind them.

4Rheology — PV, YP & gels

Drilling mud is a Bingham plastic: unlike water, it needs a minimum stress just to start moving. Plot shear stress against shear rate and two numbers fall out — the slope and the intercept.

• PV is mechanical — it rises with the count of fine solids in the fluid. A climbing PV usually means the removal train is slipping.
• YP is the gel structure that carries cuttings — mostly chemistry, tuned with the mud system.

This is the cleanest way to see why solids control is rheology control: you manage YP with chemistry, but you only manage PV by removing solids. See PV & YP explained.

5Solids in the mud — barite vs LGS

Two solids share the mud and behave like opposites:

The whole art of solids control is to remove the LGS while keeping the barite — which is exactly why a mud cleaner exists, and why a centrifuge has two opposite duties. Get this split wrong and you either discard weight material or let fine LGS strangle the rheology. See LGS & the retort and barite & sag.

6Mud weight, ECD & barite sag

Mud weight is the hydrostatic barrier, but the formation feels ECD — equivalent circulating density — which is mud weight plus the friction of pumping it. The fine-solids load raises ECD through PV, which is the bridge to lost circulation.

Barite sag is the other side: if suspension fails (flat gels, low-side wells), heavy barite settles, and you get alternating light and heavy mud — a well-control hazard. Sag is a suspension problem, and suspension is a properties problem kept healthy by the right solids balance. See ECD & solids load and the Lost Circulation Center for where rising ECD ends.

7Testing the mud (API RP 13B)

The daily check is standardised so any engineer reads the same number the same way (API RP 13B-1 for water-based, 13B-2 for non-aqueous):

• Mud balance — density.
• Rotational viscometer — the 600/300 dial readings that give PV and YP, plus gels.
• Retort — oil / water / solids by volume; the basis for the LGS split.
• Filter press — API fluid loss and cake thickness.
• MBT (methylene-blue) — reactive-clay content.
• Sand content kit and a Marsh funnel for quick field checks.

These tests are also exactly what a remote evaluation reads — the mud report is the window into how well the solids-control train is doing its job.

8Why fundamentals matter for solids control

→Go deeper

1What is lost circulation?

Lost circulation is the loss of whole drilling fluid from the wellbore into the formation — fluid leaving through fractures, vugs or permeable rock, not filtering through a cake. It is measured by what the pits lose, in barrels per hour.

Losses vs fluid loss — don’t confuse them. Fluid loss (API filtrate) is the small, controlled seepage of liquid through the filter cake, measured in mL. Lost circulation is whole mud — solids and all — disappearing into the formation. One is a cake-quality number; the other is a returns problem.

Operational impact: lost hydrostatic head (well-control risk), lost expensive fluid, non-productive time, and in severe cases an inability to keep the hole full. It is one of the costliest events on a well.

2Types of lost circulation

Losses are graded by rate, because the rate decides the response:

The grade is the first thing a field diagnosis establishes — it sets both the urgency and the LCM strategy.

3Common causes

Where the fluid goes tells you what you are fighting:

• Natural fractures — pre-existing open fractures that take fluid as soon as they’re intersected.
• Induced fractures — the well breaks the rock itself when ECD exceeds the fracture gradient. This is the one solids control influences most directly.
• Cavernous / vugular formations — karst, caverns and large voids that can take total losses instantly.
• Highly permeable zones — coarse sands and gravels that drink fluid through pore space (seepage to partial).
• Weak / depleted formations — low fracture resistance, easily induced once pressure creeps up.

Note the pattern: two of these — induced fractures and weak formations — are pressure-driven, and pressure is driven by ECD, which is driven by the fine-solids load. That is the SC DrillTech angle.

4Field diagnosis guide

You rarely see the loss zone — you read it from surface signs. Four signals, read together, grade the loss:

Read all four. A pit drop with full flowline returns and a falling SPP reads differently from a total loss with no returns — and the mud trend tells you whether you helped cause it at surface.

5Lost circulation & solids control

This is where SC DrillTech has something few others say. The solids-control system can either protect you from losses — or quietly make them worse and waste the LCM you’re paying for.

LCM & shale shakers

The shaker is where LCM is won or lost. Run normal screens during an LCM treatment and the deck screens out the very material you just pumped — throwing expensive fibres and flakes straight to waste. The fix is deliberate screen selection: coarsen the deck, or bypass the shaker for the LCM circulation so the material survives to the active system. See the shaker guide and screen blinding.

LCM & mud cleaners

The mud cleaner’s fine screen will also reject coarse LCM. During treatment, know when to bypass the cones / cleaner so the LCM isn’t classified out — then return to normal once the pill is placed. It’s an operational decision, not a set-and-forget. See the mud cleaner guide.

LCM & centrifuges

A centrifuge running through an LCM treatment can strip out the sized material you need in suspension, and load itself with fibrous solids it was never meant to handle. The recommendation: idle or isolate the centrifuge during active LCM work, and resume once the treatment has done its job. See the centrifuge guide.

LCM recovery & reducing unnecessary losses

Beyond protecting the pill, the bigger prize is not generating the problem: controlling ultra-fine drilled solids keeps PV and ECD down so you induce fewer losses in the first place. Better solids control upstream means fewer LCM events downstream.

Common solids-control mistakes during a loss event

• Leaving fine screens on the shaker — screening out the LCM you just bought.
• Running the centrifuge through the treatment — removing sized material from suspension.
• Forgetting to bypass the cones / mud cleaner during the pill.
• Letting LGS and PV climb unchecked — raising ECD until the formation breaks.
• Not restoring normal solids control after the pill — leaving the system half-configured.

6LCM categories

LCM is grouped by particle shape, because shape decides how it bridges and seals. An overview — sizing and selection are an expanding topic here:

Effective pills often blend all three — granular to bridge, fibrous to span, flaky to seal. Detailed selection and sizing are flagged below as coming soon.

7Economic impact

Losses are expensive on more than the fluid line. A single event compounds across the cost sheet:

• Lost mud — every barrel into the formation is barrels of base fluid and chemicals gone.
• Extra dilution & build — rebuilding lost volume, often the most expensive lever.
• Extra waste — more volume to treat and haul, especially on NAF.
• Logistics — LCM, barite and base-fluid resupply, sometimes by boat or air.
• Rig time — NPT chasing the loss is usually the biggest number of all.

Simple example: a partial loss of 30 bbl/hr on an OBM at a fully-loaded cost of a few hundred dollars a barrel runs into five figures a day before a single hour of NPT — which is why prevention at surface (controlling ECD via solids) pays for the whole solids-control effort many times over.

8Future expansion

?FAQ

→Connected across SC DrillTech