Surface Well Testing

Summary: Surface Well Testing

Surface well testing evaluates well performance and reservoir properties by creating and measuring pressure and flow changes. A successful test depends on understanding well behavior, selecting and arranging appropriate equipment, collecting useful fluid samples, and following strict safety procedures.

Key Operational Considerations

• Dynamic well conditions: Plan for how the well will respond to changes in pressure and flow rate.
• Equipment selection and layout: Choose and position surface equipment to support reliable measurements and maintain system integrity.
• Fluid sampling: Use suitable equipment to collect produced-fluid samples, which help characterize productivity and reservoir fluids.
• Safety: Handle hazardous materials properly, control well pressure, and have emergency response procedures in place.

Drawdown and Buildup

• Drawdown: A shut-in well is opened to flow. Producing fluids lowers reservoir pressure and creates a pressure disturbance.
• Buildup: A flowing well is shut in. With production stopped, reservoir pressure recovers, creating a different pressure disturbance.

Both phases are used to assess reservoir properties and well performance.

Surface Testing Equipment and Functions

Surface equipment must safely control pressure and flow, shut in the well, separate and measure oil, gas, and water, collect solids and samples where applicable, and dispose of fluids safely.

A typical equipment train may include:

• Flow head: Controls well pressure.
• Safety valve and emergency shutdown system (ESD): Support safe well control and shutdown.
• Sand filter: Collects or removes solids.
• Choke manifold: Controls flow rate and pressure.
• Heat exchanger or heater: Raises effluent temperature to help prevent hydrates in gas wells. In oil wells, it can help break emulsions, reduce foam and viscosity, and improve burning efficiency.
• Separator: Separates, meters, and allows sampling of the three fluid phases.
• Gauge or surge tank(s): Store oil, help calibrate separator liquid meters, measure shrinkage, and handle low liquid flow rates.
• Transfer pump: Empties the tank and provides pressure for atomizing oil at the burner.
• Oil and gas manifolds: Route the respective fluid streams.
• Burner(s) and burner booms, for offshore operations: Dispose of oil and gas by burning them separately. The oil burner is placed at the end of the boom to reduce heat radiation toward the rig.

Piping Systems

The equipment is interconnected with piping that is generally flexible between the flow head and choke manifold, and rigid elsewhere.

Flexible Piping

• A high-pressure flexible hose, such as a co-lexip hose with WCO or Grayloc connections, connects the flow head to the choke manifold.
• This connection allows up-and-down movement of the DST string while keeping the flow line connected.
• Longer hoses—typically 40–60 ft—can reduce the number of seals and therefore the risk of leaks or rupture.
• The hose is heavy and requires a crane for safe installation.
• Elbows may be needed at both ends to maintain the hose’s minimum bending radius and avoid damage.
• Low-pressure rubber hoses, commonly with WEO connections, are used mainly for air or water lines.

Rigid Piping

• High-pressure rigid lines commonly use WEO or Grayloc connections for secure, leak-resistant joints.
• Straight pipe sections are typically available in 1 m, 3 m, or 5 m lengths.
• Elbows, often 90-degree fittings, redirect the pipework to suit the required routing and alignment.

Speakers or Sources

• KWS eLearning: Instructional narration; no individual speaker is identified.