China Oil And Gas Separator Manufacturer Providing Multi-Phase Separation Solutions for Midstream Operations

China Oil And Gas Separator Manufacturer Providing Multi-Phase Separation Solutions for Midstream Operations

Answering the core question: What does an oil and gas separator from Shijiazhuang Zhengzhong Technology Co., Ltd deliver to midstream operations? Shijiazhuang Zhengzhong Technology Co., Ltd (Center Enamel) designs and fabricates two and three phase production separators that split wellhead fluids into gas, oil, and water by gravity settling, supplemented by inlet momentum breaking and a mist extractor. Separators operate from 1 to 100 bar with liquid retention times of 1-5 minutes for two-phase service and 3-10 minutes for three-phase service. Gas capacity is set by the Souders-Brown equation using a velocity factor K of 0.10-0.35 m/s, and a properly sized vessel with a mist extractor removes droplets above 10-500 µm, holding liquid carryover below 0.1 L per million standard cubic feet of gas.

1. How Multi-Phase Separation Works

A separator is a low-velocity vessel: its whole purpose is to slow the stream down enough that gravity can do the work. Three stages perform the separation:

• Inlet Momentum Breaking: Wellhead fluid arrives as a high-velocity, often slugging, multiphase mixture that would shred any liquid film and re-entrain droplets if admitted directly. The inlet therefore uses a diverter, a centrifugal inlet, or a cyclone that absorbs the momentum, spreads the flow, and begins primary gas-liquid separation. A poorly designed inlet is the most common cause of a separator that works on paper and underperforms in the field, because no amount of vessel volume recovers separation destroyed at the inlet. Inlet devices are selected for the expected flow regime, and where slugging is severe, a slug catcher or a larger inlet manifold is provided upstream.
• Gravity Settling: Once the bulk phases are separated, droplets settle according to Stokes' law, where terminal velocity is proportional to the square of droplet diameter and to the density difference, and inversely proportional to the continuous-phase viscosity. This is why retention time matters and why heavy, viscous crude separates more slowly than light condensate. Gas capacity is sized by the Souders-Brown equation, Vmax = K·sqrt((rhol - rhog)/rhog), with K of 0.10-0.35 m/s depending on service and on whether a mist extractor is fitted. Liquid capacity is sized by retention time, giving the vessel its diameter and seam-to-seam length.
• Mist Extraction and Coalescing: Gravity alone cannot remove fine droplets, so the gas passes through a mist extractor before leaving: a knitted mesh pad removing droplets above 10-30 µm at low pressure drop, a vane pack handling higher liquid loads and fouling service, or a cyclone bundle for high gas capacity and compact vessels. In three-phase service, liquid-liquid separation is improved by a coalescing plate pack or matrix that shortens the settling distance by giving droplets a short vertical path to a surface where they coalesce and run off, which can reduce the required vessel volume by 30-50% for difficult emulsions.

2. Configurations and Operating Problems

Separator selection is driven by phase count, gas-oil ratio, and the operating problems the stream is known to carry. Four considerations dominate:

• Two-Phase Versus Three-Phase: A two-phase separator splits gas from total liquid and is used where water production is negligible or where water is handled downstream. A three-phase separator additionally splits oil from water inside the same vessel, using a weir to set the oil-water interface and a separate water outlet, or in a bucket-and-weir design, both a weir and an internal bucket. Three-phase vessels require reliable interface level control, because the water outlet must discharge water without losing oil and the oil outlet must discharge oil without carrying water, and an interface that drifts a few centimetres can change the water-in-oil content of the sales stream enough to cause an off-spec cargo.
• Horizontal Versus Vertical: Horizontal separators are the default for three-phase service and for high gas-oil ratios, because they give a large gas-liquid interface area, a long settling path, and low gas velocity in a vessel that is easy to transport and to service. Vertical separators are preferred where plot space is limited, where the stream carries sand or solids that need a bottom drain and periodic cleanout, where liquid surge capacity is needed, or where the gas-oil ratio is very low and the vessel is sized by liquid retention. Many facilities use a vertical scrubber upstream of a horizontal three-phase separator.
• Foam, Emulsions, Paraffin and Sand: Four field problems defeat textbook separator design. Foaming crude creates a stable foam layer that occupies vessel volume and carries liquid into the gas outlet, managed by inlet cyclones, foam breaking internals, and chemical injection. Tight oil-water emulsions resist gravity separation, requiring heat, chemical demulsifier, or electrostatic coalescing. Paraffin and asphaltene deposits build on internals and reduce capacity, managed by heat and by removable internals. Sand accumulates and occupies volume, so vessels include sand jets, sand drains, and in severe service a dedicated desander upstream. Each of these should be identified at the design stage from field data.
• Instrumentation, Control and Sizing Standards: Reliable operation depends on level control: a level controller on the liquid outlet, an interface controller on the water outlet in three-phase service, and independent high and low level alarms and shutdowns to prevent liquid carryover to the gas system or gas blowby to the liquid system. Pressure is controlled on the gas outlet, and relief protection is sized for the blocked-outlet and fire cases. Designs follow API 12J for oil and gas separators and ASME VIII Division 1 for the pressure boundary, and sizing should be based on actual fluid properties, flow rates, and gas-oil ratio rather than on a rule-of-thumb retention time alone.

Oil and Gas Separator Configurations Comparison Matrix

Frequently Asked Questions (FAQ)

Q: How is a separator sized?

A: By two independent calculations, and the larger result governs. Gas capacity uses the Souders-Brown equation, Vmax = K·sqrt((rhol - rhog)/rhog), where K is an empirical velocity factor of 0.10-0.35 m/s chosen from service experience and modified for pressure, for the presence of a mist extractor, and for foaming tendency; the required cross-sectional area follows from the actual gas flow at operating conditions. Liquid capacity uses retention time: typically 1-5 minutes for two-phase service and 3-10 minutes for three-phase oil-water separation, with longer times for viscous crude and for tight emulsions. The vessel diameter comes from the gas requirement and the length from the liquid requirement, checked against a length-to-diameter ratio that keeps the flow reasonable, commonly 3:1 to 5:1.

Q: What causes liquid carryover in a gas separator and how is it fixed?

A: Four causes, in order of frequency. Inlet design: if the incoming momentum is not dissipated, droplets are re-entrained faster than gravity can remove them, and no increase in vessel size compensates. Foaming: a stable foam layer occupies the settling space and is carried directly to the gas outlet, which is a chemical problem requiring antifoam injection rather than a mechanical one. Overloading: actual gas flow above the design rate, from higher production or from slugging, raises velocity beyond the Souders-Brown limit. Damaged or fouled mist extractor: a mesh pad that is dislodged, corroded, or blocked by paraffin or salt stops removing fine droplets. Diagnosis starts with measuring actual flow against design and inspecting internals at the next shutdown.

Q: Why is interface level control so critical in a three-phase separator?

A: Because the oil and water outlets are both located on the same vessel and the separation quality depends entirely on where the interface sits. If the interface rises too high, water exits through the oil outlet and the sales crude exceeds its basic sediment and water specification, which can result in rejected cargo, pipeline penalties, or downstream processing problems. If it falls too low, oil exits through the water outlet, which wastes product, overloads the produced water treatment system, and can breach discharge permits. A drift of only a few centimetres can be enough to move water-in-oil from a compliant 0.5% to an off-spec 2%. Reliable service therefore requires a dedicated interface level measurement, often using a capacitance or guided-wave radar probe, with independent alarms and regular verification against a manual gauge.

Q: What standards apply to oil and gas separators?

A: Three layers. Design and sizing of the separation vessel follow API 12J, which gives the sizing methodology, the recommended K-factors, retention times, and guidance on internals and on handling foam, sand, and paraffin. The pressure boundary is designed and stamped to ASME VIII Division 1, or to the equivalent local code in the installation jurisdiction, with material, welding, and non-destructive examination requirements appropriate to the service. Where the fluid is sour, containing hydrogen sulphide, materials must additionally comply with NACE MR0175 or ISO 15156 for resistance to sulphide stress cracking, which restricts hardness and material condition and often requires post-weld heat treatment and hardness testing of production welds.