Chemicals for oil and gas

Oil and gas production runs on a short list of process chemicals. In amine treating units, monoethanolamine (MEA) absorbs hydrogen sulfide and carbon dioxide from sour gas so it meets pipeline limits, typically a quarter grain of H2S per 100 standard cubic feet, about 4 ppm. The rich amine is stripped with heat and reused.

In gathering lines, gas and free water form ice-like hydrates at high pressure and low temperature. Methanol or monoethylene glycol (MEG) injected upstream prevents them; glycol dehydration units, by contrast, mostly run triethylene glycol. Well work uses hydrochloric acid to dissolve carbonate rock and near-wellbore damage, acetic acid where a slower acid suits hot wells, and calcium chloride brine to control pressure during completions. Xylene and toluene dissolve paraffin and asphaltene deposits.

A change in concentration or water content changes how each of these works, so know the specification before the product reaches the site.

Most field chemistry runs on technical grade, where solvency or reactivity is the goal and trace impurities do not matter. Grade starts to matter where a specific impurity does.

Sodium hydroxide 50% membrane grade carries far less sodium chloride than diaphragm grade. That matters in boiler feed and stainless steel service, where chloride drives stress corrosion cracking. Water content matters in methanol for hydrate control, because injection rates assume nearly pure methanol. ACS reagent grades belong in the laboratory, for amine strength titrations and other analysis, not in a field injection pump.

Check the product name for the grade, and compare the SDS and COA with the specification your engineer wrote. The cost of a failed seal or a cracked component is far larger than the price difference between grades.

OSHA's Process Safety Management standard (29 CFR 1910.119) covers processes holding listed highly hazardous chemicals above threshold quantities, or 10,000 lb or more of flammable liquid or gas in one process, with exceptions such as unrefrigerated atmospheric storage. It excludes oil and gas well drilling and servicing and normally unoccupied remote facilities, but gas plants and refineries are usually in scope. EPA's Risk Management Program (40 CFR Part 68) applies separately to listed substances above its thresholds.

Every chemical needs a current SDS under OSHA Hazard Communication (29 CFR 1910.1200) and must be on the TSCA inventory or exempt. Hydrochloric acid, methanol and caustic ship as hazardous materials under DOT rules in 49 CFR. Offshore discharges fall under EPA NPDES permits. Consult your regulatory team for basin and state requirements.

• Injecting a premix where the design calls for concentrate. A 50/50 glycol carries half the hydrate inhibitor per gallon, and an underdosed line can plug with hydrates.
• Using kerosene on asphaltenes. Asphaltenes do not dissolve in paraffinic solvents such as kerosene. They need an aromatic such as xylene or toluene.
• Swapping acetic acid for hydrochloric acid at the same volume. Acetic acid is weaker and dissolves less carbonate per gallon, so the job design has to change.
• Ignoring seals. Xylene and toluene swell nitrile, and amines attack fluoroelastomers.
• Storing 50% caustic outside in winter. It crystallizes at about 54 °F (12 °C) and plugs tanks and lines.