Tubing Performance Curve (TPC)

Key Takeaways

• The intersection of the TPC and IPR defines the natural flow rate and flowing bottomhole pressure of the well, and shifting either curve changes the operating point — the IPR describes reservoir behavior: higher permeability gives a flatter (less steep) IPR with higher potential rates at a given bottomhole pressure; higher skin gives a steeper IPR that limits rate at all bottomhole pressures; the TPC describes tubing behavior: larger tubing, lower wellhead pressure, and higher GOR produce a TPC with lower bottomhole pressure requirements and better lifting performance; the intersection of the two curves is the well's operating point under natural flow; by calculating how changes in wellhead pressure (from adding or removing a wellhead choke), tubing ID (from replacing a smaller tubing with a larger size), or artificial lift (gas lift injection raising the effective GOR, or pump addition reducing the effective bottomhole pressure requirement) shift the TPC, the production engineer identifies the changes that maximize the operating rate within the constraints of the surface facility and reservoir capacity; nodal analysis — the systematic analysis of pressure losses at each node of the production system from reservoir to separator — uses the TPC as the tubing node characterization and combines it with inflow, wellhead choke, flowline, and separator constraints to find the system-wide optimum.
• Tubing size selection for a new well is one of the most consequential decisions made before the well is completed, because the tubing cannot be changed without a full workover once the well is producing — the TPC for a 2-3/8 inch tubing and a 3-1/2 inch tubing are significantly different, with the larger tubing providing a lower bottomhole pressure requirement (better lifting performance) at all rates above the minimum where friction losses are negligible; for a well producing 500 bbl/day oil with 2,000 bbl/day water and 500 Mscf/day gas, a 3-1/2 inch tubing might require 200-300 psi less bottomhole pressure than a 2-3/8 inch tubing at the same rate, which translates directly to 200-300 psi more drawdown available from the reservoir and potentially 50-100 bbl/day more oil production; over the producing life of the well, that incremental production can represent millions of dollars in additional revenue; the cost of the larger tubing (typically $5-20 per foot more for the steel alone) is almost always recovered within the first year from the incremental production; tubing size selection errors — selecting tubing too small for the well's eventual productivity — are among the most common and most costly production engineering mistakes, and they are irreversible without a workover that costs $500,000-$2 million.
• Gas lift performance analysis relies heavily on TPC construction because gas lift works by shifting the TPC to lower bottomhole pressure requirements — gas lift injection adds gas to the production stream in the tubing, increasing the mixture GOR and reducing the hydrostatic gradient of the flowing fluid column; as the GOR increases (from the injected lift gas), the TPC shifts downward, meaning the well can flow at the same production rate with a lower bottomhole pressure, or can flow at a higher rate with the same bottomhole pressure; the TPC for a gas-lifted well is constructed for each injection rate (which determines the incremental GOR added by the lift gas), and the optimum injection rate is found by plotting the TPC for multiple injection rates and selecting the rate that maximizes oil production (the rate where the IPR-TPC intersection produces the highest oil rate); above an optimum injection rate, the additional friction from the high-velocity gas actually increases the TPC (increases the required bottomhole pressure), causing oil production to decrease even as gas injection continues to increase — a phenomenon called over-injection that wastes compression energy and reduces production; the optimal gas lift injection rate for each well is typically 200-2,000 Mscf/day, depending on the well's productivity, water cut, and tubing configuration, and it changes as the reservoir depletes and the well's GOR and WOR evolve.
• Critical flow rate and liquid loading are TPC concepts that determine when an oil or gas well begins to die from insufficient velocity in the tubing — at very low flow rates (approaching the minimum on the TPC), the mixture velocity in the tubing is too low to continuously transport liquids to surface; in gas wells, liquid water or condensate accumulates in the low points of the tubing in the form of slugs that the gas phase cannot lift; as liquid accumulates, the hydrostatic pressure increases, reducing the drawdown available to the reservoir and causing the well to die progressively from liquid loading; the critical flow rate (Turner rate for gas wells) is the minimum gas velocity required to continuously lift the liquids produced by the well, calculated from the wellbore geometry, gas density, and liquid droplet terminal velocity; below this critical rate, liquid loading begins; above it, the well produces stably; managing the approach to liquid loading — by reducing wellhead pressure (beanchoking), installing velocity strings (smaller tubing inside the existing tubing to increase gas velocity), or injecting surfactant (foam to reduce liquid surface tension and improve transport) — extends the producing life of wells that are approaching their natural decline toward liquid loading and eventual death.
• TPC construction for high GOR wells and gas wells requires multi-phase flow correlations that accurately model the hydrodynamics of gas-liquid flow in vertical and deviated tubing — the TPC is not calculated analytically but is computed using empirical or mechanistic correlations for pressure gradient in two-phase flow (Hagedorn-Brown, Beggs-Brill, Duns-Ros, OLGAS, and other correlations) that were developed from flow loop experiments and field data; each correlation has accuracy advantages and disadvantages depending on the gas-liquid ratio, tubing inclination, fluid properties, and flow regime; for high-GOR wells (GOR greater than 3,000 scf/bbl) and gas wells, gas-dominated flow correlations provide better accuracy than oil-dominated correlations; for horizontal and deviated well sections, correlations that specifically account for inclination effects (Beggs-Brill and mechanistic models) are required; modern commercial production engineering software (PROSPER, Pipesim, REVEAL) provides the analyst with a library of correlations and allows calibration of the correlation against actual well test data by matching the predicted TPC to the measured flowing bottomhole pressure at a known production rate, selecting the correlation that gives the best match and using it for extrapolation to other conditions.