Fullbore

Key Takeaways

• Wellhead and Christmas tree bore diameter selection is one of the most consequential fullbore decisions in well completion design because it defines the maximum size of any tool, pump, or production equipment that can ever access the reservoir through the wellhead during the well's producing life — a wellhead and tree with a 2-7/8 inch bore will forever limit the production tubing, wireline tools, and downhole pump diameter to what can fit through a 2-7/8 inch opening; if the reservoir later requires a larger ESP (because water production increases and a higher-capacity pump is needed) or a larger diameter workover tool (for a scale removal operation), the undersized wellhead becomes an expensive bottleneck that requires either wellhead replacement (costly and requiring production shutdown) or living with the performance limitation; the opposite problem (oversizing the wellhead bore for future tools that are never needed) adds upfront capital cost for capacity that is never used; getting the wellhead bore specification right requires forecasting the likely production enhancement and intervention tools that will be needed throughout the well's producing life, which is a reservoir and completions engineering judgment call made at well design stage with uncertain future information.
• Fullbore ball valves are the preferred isolation valve for pig launcher and receiver systems because pigging requires the valve bore to equal the pipeline bore — a cleaning or inspection pig launched into a pipeline must pass through every valve in the system, and a reduced bore valve would catch and stop the pig, causing a pig stuck in the valve that requires disassembly to retrieve; ball valves achieve a fullbore condition by drilling or casting the ball's through-hole to the same diameter as the pipe, allowing the pig to pass smoothly when the valve is open; the trunnion-mounted ball valve design (where the ball is held in place by trunnion bearings rather than floating against the seats under pressure) is preferred for large-diameter, high-pressure fullbore applications because it provides more precise ball positioning and better sealing under the larger forces involved in big-bore service; in pipeline operations, a fullbore valve that is mistakenly operated to a partially open position (restricting the bore) while a pig is in transit can create a stranded pig situation — the pig arrives at the partially closed valve, stops, and the pipeline either builds excessive pressure behind the stuck pig or must be depressurized and the pig manually retrieved.
• Coiled tubing operations require fullbore wellhead and tree equipment to allow the coiled tubing to reach the target depth without restriction — the coiled tubing string (which can range from 1 inch to 3-1/2 inch OD depending on the application) plus the downhole BHA (which may be several inches larger than the CT OD) must pass through the wellhead master valve and all Christmas tree valves to reach the wellbore; a wellhead or tree with reduced-bore valves may prevent the BHA from passing, requiring either a different (smaller) BHA configuration or wellhead modification before the CT job can proceed; offshore wells designed for regular coiled tubing intervention during their producing life are therefore specified with fullbore tree equipment that accommodates the expected CT and BHA sizes, even though the initial cost premium for fullbore versus reduced bore wellhead components may be tens of thousands of dollars; this design-for-intervention philosophy is particularly important in deepwater subsea completions where wellhead modification after installation is extremely expensive or impossible without major subsea tree intervention.
• The hydraulic advantage of fullbore over reduced bore equipment is quantified by the pressure drop (head loss) through the restriction — the pressure drop through a reduced bore fitting is proportional to the square of the velocity increase through the restriction, which increases as the square of the area ratio between the pipe ID and the reduced bore; a valve with a bore 50% of the pipe diameter creates a velocity 4 times the pipe velocity, producing 16 times the local pressure drop of an equal pipe length; for low-flow-rate, low-pressure-drop systems, the pressure drop through a reduced bore valve may be negligible; for high-rate gas wells producing at near-maximum deliverability (where every psi of pressure drop through a valve reduces production rate), the pressure drop through a reduced bore master valve can cost measurable production and NPV, justifying the fullbore premium on pure hydraulic grounds; wellbore deliverability calculations (nodal analysis) should include the pressure drop contributions of all production system components, including valves and fittings with their associated bore restrictions, to correctly identify where hydraulic restrictions are costing production.
• Fullbore completions in horizontal wells enable through-wellbore stimulation and intervention tools to reach perforations and reservoir zones throughout the lateral — in a horizontal well with a fullbore completion string (sliding sleeves, ball-activated ports, or open hole packers with fullbore mandrels), coiled tubing, wireline, or production logging tools can be run to any position in the lateral without restriction; reduced bore components in the completion string (undersized valve mandrels, flow control devices with small internal diameters) prevent these intervention tools from reaching the section of the lateral below the restriction, effectively making that section inaccessible for diagnostics, stimulation, or water shut-off operations throughout the well's life; this is why completion designers who anticipate future interventions (remedial cementing, plug-and-perf frac restimulation, production logging to identify water breakthrough zones) specify fullbore sliding sleeves and mandrels even when the initial completion doesn't require the full bore clearance — the future intervention requirement that justifies the design may not be predictable at completion design stage, but leaving the bore available costs less than reworking the completion later.