Drill Solids

Drill solids (also called drilled solids or formation solids) are the solid particles of formation rock — including sand grains, clay minerals, silt, carbonates, and other lithic fragments — that are generated by the drill bit cutting the formation, enter the drilling fluid returns at the shale shakers, and if not removed by solids control equipment accumulate in the active mud system as a continuously increasing contaminant that raises plastic viscosity, yield point, and gel strengths, degrades filter cake quality, occupies pore volume in the mud system that should be available for weighting material, and causes excessive wear in mud pumps, drill bit bearings, and other rig equipment; drill solids are considered inherently detrimental to mud performance in almost all circumstances and should be removed from the active mud system as quickly and as completely as the available solids control equipment allows — with the fundamental principle being that drill solids should be removed while they are at their largest possible size (freshly cut cuttings at the primary shaker), because solids that are recirculated through the pumps and bit are progressively ground to finer particle sizes that are progressively more difficult to remove by any mechanical separation method.

What Are Drill Solids?

Every time the drill bit advances, it generates rock fragments that enter the drilling fluid returns. These drill cuttings are the material the bit is paid to cut — and once they've served their purpose as evidence of the formation being drilled, they become a problem. Unlike the carefully engineered bentonite, barite, and polymer additives in the mud system, drill solids are an uncontrolled contaminant of variable mineralogy, particle size, and surface chemistry that interfere with the mud's designed performance in almost every measurable property.

The critical insight in drill solids management is timing. A large drill cutting removed at the primary shaker is one particle per shaker screen pass. That same cutting ground through the pump and bit four times becomes hundreds of fine particles, each smaller than any screen can capture and each with greater surface area contributing more viscosity per unit volume than the original particle. The cost of failing to remove a drill cutting at the first opportunity compounds with every circulation cycle.

This is why the engineering principle of drill solids management is "remove first, remove while large" — maximize shaker screen area and efficiency, use the finest practical mesh screens for the mud weight and formation, operate all available downstream solids control equipment, and measure drill solid content frequently enough to detect the early stages of accumulation that signal equipment maintenance or process adjustment requirements before the drill solid burden degrades mud properties to the point where remediation requires expensive dilution or mud dump-and-replace operations.

Drill Solid Management Through the Solids Control Equipment Train

Optimizing the primary shale shaker for drill solid removal requires balancing screen mesh fineness against circulation rate and available screen area — finer screens (smaller mesh opening, such as 200 to 325 mesh) remove smaller drill solid particles but have lower throughput per unit area and more frequent plugging requiring screen replacement; coarser screens (100 to 140 mesh) handle higher circulation rates and resist blinding but allow smaller drill cuttings to pass through to the active system; the optimum screen selection for a given mud system and formation type is the finest screen that processes the full circulating rate without overflowing at acceptable screen life economics; in high-solids-loading situations (drilling through soft shale or unconsolidated sand), the primary shaker may need to use courser screens to handle the load, with a secondary shaker processing the overflow at finer mesh to capture the medium-fine particles that pass the primary screens under high-loading conditions.

Centrifuge operation for drill solid management concentrates the ultra-fine drill solid fraction (less than 10 to 25 microns) in the high-gravity discharge and recovers the cleaned low-solids liquid in the overflow for return to the active system — for unweighted muds, the centrifuge is typically operated at maximum speed to maximize fine solid removal (accepting barite loss in the high-gravity discharge); for weighted muds, the centrifuge speed may be reduced to separate fine drill solids from barite, recovering barite in the overflow while concentrating the finest drill solids in the discharge; this weighted mud centrifuge application (sometimes called the "salvage" centrifuge mode) is the most economical approach for maintaining drill solid content in expensive weighted OBM systems because it recovers valuable base oil and barite while removing the drill solids that degrade performance.

Drill Solids Across International Jurisdictions

Canada (AER / WCSB): AER requires that drill solid content in active mud systems be reported on the daily drilling report submitted for regulated WCSB wells, with PV trends (the primary proxy for drill solid accumulation) and retort solids analysis providing the quantitative data; WCSB horizontal well programs specify maximum acceptable drill solid content levels in the mud program, typically expressed as maximum PV (18 to 25 cP depending on mud weight) and maximum total solids volume fraction from retort analysis (5 to 8% by volume for unweighted mud); Canadian drilling contractors operating in the WCSB typically employ a mud engineer from the mud service company (Baker Hughes, SLB, Halliburton) on each rig to monitor drill solid accumulation and operate solids control equipment according to the mud program specifications submitted to AER.

United States (API / BSEE): API RP 13C (Recommended Practice on the Evaluation of Lost Circulation Materials) and RP 13B provide the US industry framework for drill solid monitoring and solids control; BSEE offshore drilling regulations under 30 CFR Part 250 require documentation of mud properties including solids content in the drilling report, and BSEE inspectors review drill solid monitoring records as evidence of mud program compliance during offshore facility inspections; in US unconventional plays where horizontal wells are drilled with synthetic-base muds, drill solid management is particularly critical because the expensive SBM base fluid cost makes mud dilution to reduce drill solid content significantly more expensive than in WBM systems, driving operators to maximize mechanical solids removal to reduce dilution volume.

Norway (Sodir / NORSOK): NCS drill solid management under NORSOK D-010 and Sodir's drilling regulations requires that active mud systems be maintained within the specifications established in the well program submitted to Sodir, with PV and retort solids analysis frequency specified in the mud monitoring program; NCS operators maintain detailed drill solid trend records as part of the formation evaluation log for each well, using drill solid accumulation trends to identify drilling intervals with high formation clay content that correlate with wellbore instability risk; Sodir's environmental regulations add a drill solid disposal dimension — OBM and SBM drill cuttings with retained oil content must be managed per OSPAR requirements, and the drill solid separation efficiency of onboard solids control equipment directly affects the oil-on-cuttings content that determines whether cuttings can be discharged overboard or require collection for onshore disposal.