Produced Fluid

Key Takeaways

• Produced water composition reflects the geochemical history of the formation it originated from, with major cation concentrations (sodium, calcium, magnesium, barium, strontium) and anion concentrations (chloride, bicarbonate, sulfate) that can be used as chemical fingerprints to distinguish water from different reservoir intervals (for production allocation in commingled wells), identify the origin of formation water (connate versus injected seawater versus aquifer water) and predict scale deposition risk (barium and sulfate concentrations that when combined in the wellbore or surface system exceed the solubility product of barium sulfate, BaSO4, will precipitate scale that plugs perforations and equipment); total dissolved solids (TDS) in produced water ranges from fresh water (less than 1,000 ppm TDS in some shallow sandstone formations) to ultra-high salinity brines (greater than 300,000 ppm TDS in Permian Basin deep formations and some Middle Eastern reservoirs) that require specialized treatment before any disposal or reuse option is feasible; radioactive scaling (naturally occurring radioactive material, NORM, including radium-226 and radium-228 co-precipitated with barium sulfate scale in some North Sea and Permian Basin wells) creates radiation protection and waste disposal obligations that go beyond standard scale treatment.
• Phase behavior of produced fluids during pressure and temperature reduction from reservoir to separator is described by the pressure-volume-temperature (PVT) model of the specific fluid system, which predicts the quantity and composition of gas liberated from oil (gas-oil ratio, GOR), the liquid that condenses from gas (condensate-gas ratio, CGR), and the water that separates from the hydrocarbon phase as temperature drops (water dropout from saturated gas streams); the flash liberation (single-stage separation at separator conditions), the differential liberation (multiple-stage separation approximating the wellbore flow conditions), and the separator test (laboratory measurement at the actual separator temperature and pressure) are the three standard PVT tests that characterize the phase behavior of produced oil; the shrinkage factor (the ratio of stock tank oil volume to reservoir oil volume, the inverse of the formation volume factor Bo) quantifies how much the oil shrinks from reservoir conditions to surface conditions as solution gas is liberated, typically ranging from 1.05 to 1.80 for Black oils and from 1.5 to greater than 3.0 for volatile oils and gas condensates, with higher shrinkage factors indicating more solution gas and more gas liberation during production.
• Produced water treatment for reinjection, overboard discharge, or surface disposal employs a multi-stage treatment train tailored to the specific produced water composition and the applicable regulatory discharge standard: primary treatment (de-oiling using gravity separators, hydrocyclones, and induced gas flotation, IGF) reduces the oil-in-water concentration from the inlet value of typically 500 to 5,000 ppm down to the regulatory limit for overboard discharge (typically 30 ppm oil in water for North Sea OSPAR compliance, 29 ppm for US Gulf of Mexico EPA VGP permit); secondary treatment (filtration through sand, walnut shell, or mixed media filters) reduces suspended solids that would plug the injection formation during water injection; tertiary treatment (membrane filtration, reverse osmosis, or chemical softening) removes dissolved solids, hardness ions, and scale-forming components before seawater injection into sensitive formations or before produced water reuse for agricultural or industrial applications; offshore produced water management decisions (treat and discharge, or collect and reinject) are driven by the volume of produced water (which can exceed 10 barrels of water per barrel of oil in mature high-water-cut fields), the cost of treatment (overboard treatment is cheaper than injection), and environmental regulations that restrict discharge in sensitive areas.
• Produced gas handling encompasses the separation of gas from the liquid phases at the separator, the compression and export of sales gas meeting pipeline specifications (typically less than 4 ppm H2S, less than 2 percent CO2, hydrocarbon dew point below the minimum ambient temperature), and the management of associated gas that cannot be sold (due to pipeline capacity constraints, gas composition outside specification, or remote location) by flaring, fuel gas use, or reinjection; acid gas treating (removal of H2S and CO2 from the produced gas using amine absorption in a gas sweetening unit) is required when produced gas contains more than the pipeline specification level of these components, generating an acid gas stream (concentrated H2S and CO2) that must be disposed of by sulfur recovery (Claus process) or acid gas reinjection (compressing the H2S and CO2 mixture and reinjecting it into a disposal formation, the preferred environmental solution in Canada where H2S reinjection has been practiced at multiple Alberta sour gas plants since the 1990s); methane slip (unintended leakage of methane from produced gas handling equipment) is a major focus of emissions reduction programs because methane is a potent greenhouse gas with approximately 80 times the global warming potential of CO2 over a 20-year timeframe, and the petroleum industry's produced gas systems (including separators, compressors, storage tanks, and valves) are significant sources of methane emissions that are increasingly subject to regulatory methane detection and reporting requirements.
• Multiphase produced fluid flow assurance addresses the problems that arise from the complex interaction of gas, oil, and water in the wellbore and production system as conditions change during the life of a field: hydrate formation (solid ice-like clathrate compounds that form when natural gas contacts water at high pressure and low temperature, blocking flowlines and wellheads) is prevented by methanol or monoethylene glycol (MEG) injection at the wellhead or through downhole injection mandrels; wax deposition (solid paraffin crystals deposited on cold pipe walls) is prevented by thermal insulation, chemical wax crystal modifiers, or periodic pigging; asphaltene deposition (heavy aromatic hydrocarbons that precipitate when reservoir pressure drops below the asphaltene onset pressure) is prevented by chemical dispersants or managed by periodic xylene or toluene solvent treatments; emulsion stability (the formation of water-in-oil or oil-in-water emulsions that resist separation in the production separator) is addressed by chemical demulsifier injection and adequate separator residence time; each of these flow assurance issues is driven by a change in the produced fluid composition or thermodynamic state as fluids travel from the reservoir to the surface, and the flow assurance management plan for each field is specifically tailored to the produced fluid PVT properties and the production system thermal-hydraulic profile.