Well Test Equipment

How a surface test spread works

A well test flows the reservoir to surface in a controlled way so you can measure rates, pressures and fluid properties. The flowhead (surface test tree) sits on the landing string and carries the master, swab, kill and flow wing valves. The flow wing valve is often hydraulically actuated and tied to the emergency shutdown system.

Downstream, the data header gives pressure, temperature and sampling points. A sand filter or desander protects the equipment, and the choke manifold sets the flow rate with fixed and adjustable chokes. The heat exchanger warms the flow to prevent hydrates and wax. The separator splits gas, oil and water for metering and sampling. Gas and oil then go to the burners on booms, or oil goes to a surge or gauge tank.

Configurations

• Flowheads and choke manifolds by API Spec 6A pressure class, commonly 10,000 or 15,000 psi.
• Two-phase or three-phase test separators, horizontal or vertical.
• Steam heat exchangers fed from a boiler, or indirect fired heaters where fired equipment is permitted.
• Burners with clean-burning heads and water curtains, on single or dual booms.
• Data acquisition systems with wired or wireless sensors.

Key specifications

Standards and certification

API Spec 6A governs the flowhead, valves and choke manifold, including pressure class, product specification level and material class. Parts that see hydrogen sulfide need NACE MR0175 / ISO 15156 materials, shown on the original material certificates. Separators, heater shells and tanks are built to ASME Section VIII or the EU Pressure Equipment Directive, and their relief valves are sized to API 520 and API 521. Skids carry DNV 2.7-1 or 2.7-3 certificates, and electrical parts need ratings for their hazardous area zone.

Failure modes and inspection

• Erosion in chokes, choke manifold tees and bends, and the data header, worst on sand-producing or high-rate wells.
• Valve seat and gate wear, and leaking stem packing.
• Internal corrosion and pitting in vessels, piping and heat exchanger tubes, often after acid or sour wells.
• Fatigue cracking in boom structures and burner heads.
• Sensor drift in meters and pressure transmitters.

Inspection runs ultrasonic wall thickness surveys on piping and vessels, internal visual inspection of the separator, hydrostatic body tests on the flowhead and manifold, and function tests of the actuated valves and emergency shutdown.

Documentation

• API Spec 6A certificates of conformity and material certificates for every upstream part.
• Hydrostatic test charts with dates and test pressures.
• Vessel code certificates, nameplate data and the last internal inspection report.
• Relief valve test certificates and set pressures.
• Wall thickness survey history, and calibration certificates for meters and sensors.

Integration with the rig or vessel

A test spread needs deck space close to the rig floor, boom positions that suit prevailing wind, and water supply for the burner curtain and deck cooling. Tie the flowhead and spread shutdown valves into the rig's emergency shutdown system. Plan steam or fuel supply for the heater and a power and data link for acquisition. Match connection types and pressure classes between units from different fleets.

Refurbishment and when to buy what

Separators and heat exchangers are large and slow-wearing. Used ones with valid vessel certificates and a clean internal inspection often make sense. Flowheads and choke manifolds see erosion and pressure cycles, so a refurbished unit with new seals, a wall survey and a fresh hydrostatic test is the safer buy. Data acquisition systems date fast, so confirm sensor and software support before you count them as an asset. Expro, SLB and Halliburton run large well testing fleets. If the test needs gauges or plugs run on wire, see Wireline Units.