Drilling Composition TRIZ Cases

Dissolvable plugs seal wellbores via chemical breakdown, eliminating mechanical drill-out delays.

N,N-dialkyl-N,N-diallylammonium salt polymers maintain stable viscosity in brine dispersions at temperatures above 100°C.

A copolymer dispersant composition reduces paraffin deposition in crude oil by inhibiting adhesion on metal surfaces.

Degradable nanogels release multivalent cations to crosslink polymers, delaying gelation for deeper reservoir penetration.

A one-component fracturing fluid additive uses a multi-alcohol dispersant to uniformly suspend high molecular polymer thickeners and auxiliary agents.

Hybrid resin cures in situ to balance compressive strength with permeability, reducing sand production without restricting well productivity.

A treatment fluid containing a paraffin dissolver and acrolein dissolves paraffin deposits while scavenging hydrogen sulfide gas.

A viscosifier-based liquid plug transitions between gel and fluid states to separate wellbore fluids.

Host-guest complexes encapsulate guest molecules within branched polymers to deliver multiple production chemicals simultaneously.

Swellable-coated filaments expand upon contact with treatment fluids to seal perforations, diverting flow to under-treated areas.

A three-phase flue gas foam uses fly ash and nano silica to stabilize bubbles at 90% quality.

A salt-free invert emulsion drilling fluid uses glycerol and fatty dimer diamine to stabilize the internal phase.

Three distinct polymers combine to maintain fluid volume and rheological properties at 400°F and high salinity.

A corrosion inhibition composition comprising 2-substituted benzothiazole, cationic surfactant, ammonium salt, and glycol forms a protective film on metal surfaces.

A polar solvent and stabilizing corrosion inhibitor maintain composition stability across extreme temperatures and pressures.

Hygroscopic chelating agents in drill-in fluids prevent mudcake deposition and reduce filtrate invasion, maintaining reservoir permeability.

Nano-filtration lowers injection water ionic strength, preventing mineral precipitation that plugs formation passageways and reduces permeability.

Phenolic resin coating delays expanding agent hydration until after cement sets, preventing premature viscosity increase during pumping.

A magnetic permeability sensor detects cementing fluid presence in wellbores to trigger a sliding sleeve actuator.

Adding alkoxylated alcohols to supercritical carbon dioxide lowers miscibility pressure, enabling economical oil recovery from immiscible reservoirs.

Diutan polysaccharide imparts thixotropic properties to Sorel cement slurry, preventing slumping in horizontal wells.

Polyhydroxyetheramines prevent phase separation in subterranean acid treatments by maintaining solution stability at high temperatures.

A cement-forming aqueous fluid prevents fluid loss into subterranean formations using viscoelastic surfactants and magnesium powder.

Acrylonitrile-butadiene copolymer stabilizes wellbore tar, preventing adhesion to equipment and avoiding formation damage from high-pressure methods.

Solvent blends suppress disulfide odor while maintaining sulfur dissolution, avoiding extensive engineering controls.

A solvent blend with surfactants travels through wellbore fluids to dissolve residues.

A chelating agent composition enters a subterranean formation to dissolve narrow pore throats and increase permeability.

A silicon glycan combines silicone and cellulose ether properties through chemical bonding.

A rapidly dehydrating lost circulation material composition forms solid plugs to prevent fluid loss.

Weighted aqueous fluid with nut shells removes oily residues to prevent cement bond leakage.

Sophorolipid corrosion inhibitors protect metal surfaces in acidic well fluids.

Thermally responsive hydrogels thicken at target temperatures to suspend weighting agents, preventing sag and maintaining wellbore stability.

Porous silica particles immobilize asphaltene control chemicals to enable gradual release, reducing treatment frequency and operational complexity.

Electrostatic particle assembly forms a self-healing barrier on subterranean rock surfaces, preventing uncontrolled fluid pressure and reservoir expansion.

Porous microspheres in the cement matrix increase permeability while maintaining structural strength for hydrate mining.

Epoxy LCM compositions with controlled viscosity and calcium carbonate particle sizes resolve micro-cracking and fluid loss in wellbores.

Polyethylene backbone with pendant aminoalkylsulfonic acid amides modifies wellbore fluid viscosity and emulsification properties.

Organophilic clay adsorbs onto shale to inhibit swelling while the fluid maintains gel strength for wellbore stability.

Water-containing diol lubricants minimize torque and drag losses, enabling longer wellbore drilling operations.

An osmotic membrane in water-based drilling fluids controls shale hydration, reducing disposal costs while maintaining lubricity.

Ethylene bottoms heavy pyrolysis oil reduces friction in drilling fluids while converting ethylene production waste into a valuable resource.

Non-crosslinked hydroxyalkylcellulose polymer combined with non-biodegradable particulates forms a stable filter cake to control fluid loss in drilling operations.

Composite additives with sulfonated copolymers and humate grafts reduce fluid loss in cement slurries despite drilling fluid contamination.

Lignite grafted copolymer prevents high-temperature phase separation in epoxy-cement slurries, preserving compressive strength and rheological stability.