Well Potential

Key Takeaways

• Potential testing procedures vary by well type and jurisdiction but share the common purpose of measuring maximum sustainable deliverability under controlled and documented conditions: for oil wells, a potential test typically involves opening the well to maximum choke size (or removing the choke entirely for naturally flowing wells), measuring the stabilized flow rate and flowing wellhead pressure after a specified stabilization period (24-72 hours or until the rate and pressure stabilize within 2-5% variation over 2-4 hours), and recording the producing gas-oil ratio and water cut during the test period; the test results are reported as barrels per day of oil, MCF per day of gas, barrels per day of water, GOR in SCF/bbl, and WOR (water-oil ratio), all at the measured wellhead pressure or at a reference wellhead pressure using the inflow performance relationship (IPR) to normalize; many regulatory jurisdictions (Texas RRC, Alberta AER, Louisiana DNR) require well potential tests at specified intervals (annually, or after significant well work) and use the reported potential as the basis for production allowables and proration calculations in regulated fields.
• Inflow performance relationship (IPR) analysis extends the single-point potential measurement to a full deliverability curve that shows the expected production rate at any flowing bottomhole pressure (FBHP): the most widely used IPR model for oil wells is Vogel's equation (q/qmax = 1 - 0.2 x (FBHP/PR) - 0.8 x (FBHP/PR)^2, where PR is the average reservoir pressure and qmax is the theoretical maximum rate at zero FBHP), which accounts for the non-linear relationship between rate and pressure caused by dissolved gas liberation and two-phase flow near the wellbore; the composite IPR (combining Darcy flow at pressures above the bubble point with Vogel's equation below the bubble point) provides a more accurate deliverability curve for wells producing from reservoirs above and below the bubble point; the IPR curve establishes the well's potential at any given reservoir pressure, allowing the production engineer to predict the rate achievable with different artificial lift settings, different wellhead pressures, or different tubing sizes before committing to intervention costs.
• Potential testing in gas wells uses multi-rate deliverability tests (back-pressure tests) to establish the Absolute Open Flow (AOF) potential, which is the theoretical maximum rate at zero flowing wellhead pressure (the maximum the reservoir could deliver against no back-pressure) and serves as the standard reference potential for gas well performance comparison: the Simplified Deliverability Test (also called the four-point test or back-pressure test) flows the well at four different choke sizes (producing four rate-pressure pairs), plots the stabilized data on a log-log graph of pressure-squared difference versus rate (the Rawlins-Schellhardt deliverability plot), fits a straight line through the data points, and extends the line to the atmospheric pressure on the x-axis to read the AOF; the LIT (laminar-inertial-turbulent) test accounts for both Darcy flow and inertial (non-Darcy) flow effects at high gas velocities in the near-wellbore region, providing a more accurate deliverability equation for high-rate gas wells where non-Darcy effects can be significant; gas well AOF potentials in major gas fields can range from less than 1 MMSCFD in tight formations to over 500 MMSCFD in high-permeability, high-pressure reservoirs.
• Well potential decline surveillance is the practice of regularly measuring or estimating well potential and tracking its change over time to identify wells with accelerated decline relative to the expected reservoir depletion rate: a well declining faster than neighbors in the same reservoir may indicate skin damage buildup from scale, wax, or asphaltene deposition (requiring stimulation or chemical treatment), mechanical damage (tubing leak, casing collapse, pump failure in artificial lift wells), water or gas coning (requiring perforations management or choke restriction), or natural productivity heterogeneity (a well in a lower-quality zone than its neighbors); a well maintaining potential better than neighbors may indicate better reservoir quality, better stimulation geometry, or more favorable fluid properties; tracking the ratio of actual production to potential (the utilization factor) for each well and comparing it across the field provides the production surveillance picture needed to allocate intervention and maintenance resources to wells with the greatest improvement opportunity; in large fields with hundreds of producing wells, automated potential decline surveillance using real-time SCADA production data integrated with periodically measured potentials is the production management tool that identifies intervention candidates before decline becomes severe.
• Well potential in the context of field development planning represents the expected deliverability of proposed new wells at initial production, used to justify the capital investment in the well and to set the production forecast that feeds into the field development economic model: the estimated well potential for a proposed development well is calculated from the reservoir simulation model (which predicts FBHP and production rate at the planned well location based on the simulated reservoir pressure and saturation), calibrated against actual potential tests from nearby analog wells; uncertainties in initial well potential (arising from reservoir heterogeneity, uncertainty in kh, skin uncertainty from completion design assumptions, and model accuracy) translate into uncertainty ranges in the well capital efficiency metrics (cost per barrel of production capacity, payout period, net present value per well); type curves (statistical distributions of actual initial well potentials observed from a population of analog wells in the same formation and play area) are used to quantify the well potential uncertainty and generate probabilistic production forecasts that represent the range of outcomes rather than a single deterministic expectation.