Everything downstream — screen area, cone count, centrifuge hours, removal efficiency — is a response to one input number that almost nobody writes down: how fast the bit is making solids. Get that rate and the whole train stops being guesswork and becomes sizing.
Where the solids come from
The bit turns rock into cuttings at a rate set by three things: how big the hole is, how fast you are drilling it, and how much of that rock was pore space rather than solid. Multiply the hole’s cross-section by the rate of penetration and you get the bulk volume drilled per hour; subtract the porosity and you get the volume of actual solids the surface system has to handle.
This is the load the solids-control train is sized against. The industry rule of thumb is to install removal capacity for at least 100–125% of the circulating rate, but the solids the equipment must actually capture are set by this generation rate, not by the pump. Knowing it turns ‘is the shaker big enough?’ into a number you can check.
Reading the formula
The hole volume per foot in oilfield units is simply the diameter squared divided by 1029.4, giving barrels per foot — a 12¼″ hole works out to 0.1458 bbl/ft, a 17½″ hole to 0.2975 bbl/ft. Multiply that by the rate of penetration in feet per hour and you have the bulk drilling rate in barrels per hour.
The last term is porosity. A porous sandstone might be 20–30% pore space, so only 70–80% of the bulk volume is solid; a hard, tight rock is closer to 100% solid. The pore fluid either stays in the chip or joins the mud, but for sizing the removal duty you count the solid fraction. Multiply the bulk rate by (1 − porosity) and you have the drilled-solids generation rate.
What the number is for
Once you know solids are arriving at, say, 9 barrels an hour, three questions get sharper. Is the shaker screen area enough to carry that at the mud’s flow rate? Are the cyclones and the centrifuge together capable of catching the fine fraction the shaker passes? And what is the removal efficiency — the solids you actually discard divided by this generation rate? Without the denominator, SRE is uncomputable.
It also frames the economics. Every barrel of solids you fail to remove is a barrel that dilution has to displace to keep properties in range, at the full built-up cost of the mud. The generation rate is the top of that cost funnel — the reason a fast section in a big hole is exactly when the solids-control train is most likely to fall behind.
The equation
Bulk hole volume per foot (oilfield units):
V (bbl/ft) = D² ÷ 1029.4 (D in inches)
Drilled-solids generation rate:
Qsolids (bbl/hr) = (D² ÷ 1029.4) × ROP × (1 − φ)
D = hole diameter (in) · ROP = rate of penetration (ft/hr) · φ = formation porosity (fraction).
This rate is the top of the whole solids-control funnel. A big hole drilled fast is exactly when generation peaks and the train is most likely to fall behind — so it is the moment to confirm screen area, cyclone capacity and centrifuge hours against the number, not after dilution has already climbed.
Common questions
How do you calculate the drilled-solids generation rate?
Multiply the hole volume per foot (diameter² ÷ 1029.4, in bbl/ft) by the rate of penetration (ft/hr) and by one minus the formation porosity. The result is the barrels per hour of solid rock the bit is generating for the surface system to remove.
What is the hole volume per foot for a 12¼-inch hole?
12.25² ÷ 1029.4 = 0.1458 barrels per foot. For a 17½-inch hole it is 0.2975 bbl/ft. This is the bulk volume; multiply by (1 − porosity) to get the solids volume.
Why does porosity matter for solids generation?
Because pore space is fluid, not solid. A 20–30% porous rock yields only 70–80% of its bulk volume as solids the equipment must handle; a tight rock is close to 100% solid. For sizing removal duty you count the solid fraction, so you multiply by (1 − porosity).
