Petroleum, Natural Gas & Refinery Testing

Refinery wastewater testing typically includes screening for contaminants that can affect discharge quality, treatment performance, equipment integrity, and environmental risk. Common parameters include oil and grease, total organic carbon, COD/BOD, ammonia, sulfide, phenols, volatile organic compounds, semi-volatile organic compounds, anions, organic acids, and trace metals. EPA petroleum refining effluent guidelines are defined under 40 CFR Part 419, which addresses wastewater discharges from petroleum refineries.

A robust refinery wastewater monitoring program may combine ion chromatography or HPIC for anions and organic acids, ICP-OES or ICP-MS for metals, GC-MS for VOCs/SVOCs, discrete analysis for wet chemistry parameters, and sample preparation technologies such as accelerated solvent extraction. Common method families include EPA 300 and EPA 300.1 for anions by ion chromatography, EPA 8260 and EPA 524.4 for volatile organic compounds, EPA 8270 for semi-volatile organic compounds, and EPA 624 for purgeable organics. Depending on the target analytes, laboratories may use HPIC/IC, GC-MS, ICP-OES, ICP-MS, discrete analyzers, and solvent extraction workflows to support wastewater monitoring, process control, and discharge documentation.

In amine treating, sour gas treatment, and acid gas removal workflows, laboratories typically monitor the chemistry of the amine solution to understand solvent health, corrosion risk, and treatment efficiency. Important measurements include amine concentration, heat-stable salts, degradation products, organic acids, chloride, sulfate, thiosulfate, metals, and other ionic contaminants.

These measurements help operators identify when the amine system is losing efficiency or becoming more corrosive. In gas treating, amine scrubber solutions are used to remove CO₂ and H₂S from process streams; if degradation products and heat-stable salts build up, the solution can contribute to corrosion, foaming, poor acid gas removal, and higher solvent reclaiming costs.

Water chemistry testing helps refineries detect conditions that lead to corrosion, scaling, fouling, pitting, stress-corrosion cracking, heat exchanger efficiency loss, and unplanned maintenance. In refinery systems, even low-level contaminants such as chloride, sulfate, organic acids, sulfide, ammonia, dissolved metals, and hardness-related ions can contribute to asset degradation when they are not controlled.

Routine testing of cooling water, boiler water, wastewater, sour water, and amine scrubber solutions allows teams to adjust treatment chemicals, identify process leaks, monitor contaminant ingress, and verify that water treatment units are operating correctly.

Natural gas BTU analysis and pipeline gas quality testing are typically performed using gas chromatography. The analysis measures the hydrocarbon composition of natural gas such as methane, ethane, propane, butanes, pentanes, and heavier hydrocarbons, along with non-hydrocarbon components such as nitrogen, carbon dioxide, oxygen, hydrogen sulfide, helium, and hydrogen, depending on the method and instrument configuration. The resulting composition data can be used to calculate heating value, BTU content, relative density, compressibility, Wobbe Index, and other parameters relevant to natural gas quality assessment.

Water dew point measures the temperature and pressure conditions at which water vapor condenses from natural gas. It is important because excess water can contribute to pipeline corrosion, hydrate formation, freezing, and operational problems.

Hydrocarbon dew point measures the conditions at which heavier hydrocarbons condense from the gas phase into liquid. This is important because hydrocarbon liquid dropout can affect pipeline operation, gas processing, compressor reliability, and product quality. Pipeline gas quality evaluations often consider HHV/BTU, H₂S, CO₂, nitrogen, oxygen, water dew point, and hydrocarbon dew point together when checking gas against tariff or contractual specifications.

Before running a new crude slate, refineries typically test for contaminants that can affect crude valuation, corrosion control, desalter performance, catalyst life, emissions, and downstream product quality. High-priority crude oil contaminants include sulfur, nitrogen, nickel, vanadium, iron, sodium, salts, chlorides, organic acids, water and sediment, mercury, arsenic, and other trace metals.

Metals such as nickel, vanadium, iron, and sodium are especially important because they can affect crude oil and residual fuel value, and nickel and vanadium can deactivate catalysts during processing. ASTM methods such as D5708 and D5863 address determination of these metals in crude oils and residual fuels.

Generating a Certificate of Analysis (CoA) may involve established analytical methods, controlled sample handling, instrument calibration, defined specifications, and documented data review. For fuels and hydrocarbon products, a CoA may include composition, sulfur, oxygenates, aromatics, boiling range, metals, density, calorific value, and other product-specific parameters, depending on the product and applicable requirements.

Analytical technologies used in these workflows may include GC and GC-MS for hydrocarbon composition and volatile impurities, ICP-OES or ICP-MS for elemental contaminants, LC for selected liquid fuel workflows, FTIR or UV-Vis for targeted product checks, and chromatography data systems or LIMS to support electronic record management and data traceability.