deliverability test, Oil & Gas Glossary

What Is a Deliverability Test?

Deliverability test (also called a back-pressure test or flow test) is a well evaluation procedure conducted on a gas well to determine its ability to produce against varying wellhead back-pressures. The test generates an inflow performance relationship (IPR) — commonly expressed as a deliverability curve on a log-log plot — that predicts production rates the well will sustain at the actual flowing pressures imposed by surface facilities and pipeline operating conditions. Deliverability testing is a regulatory requirement in most producing jurisdictions and is fundamental to pipeline contract negotiations, facility design, and reserve certification.

Key Takeaways

Deliverability tests quantify a gas well's absolute open flow (AOF) potential — the theoretical maximum rate if wellhead pressure were reduced to atmospheric — which serves as the benchmark for all production rate comparisons.
Four standard test types exist: the conventional back-pressure test, the isochronal test, the modified isochronal test, and the single-point test; the choice depends on reservoir permeability and the time available.
The deliverability curve plots the stabilized flow rate against the pressure-squared differential on a log-log scale; the slope of this line defines the laminar (Darcy) and turbulent (non-Darcy) flow components.
Laminar-inertial-turbulent (LIT) analysis separates the Darcy skin damage from rate-dependent turbulence losses, enabling engineers to determine whether productivity improvement requires stimulation or simply reduced flow velocity.
Regulatory agencies including the Texas Railroad Commission, the Alberta Energy Regulator, and the Louisiana Office of Conservation require deliverability tests before setting allowable production rates for gas wells.

How a Deliverability Test Works

A deliverability test imposes a series of controlled flow rates on a gas well, recording stabilized bottomhole or wellhead pressures at each rate. The fundamental principle is that gas flow through a reservoir is governed by Darcy's law at low velocities but deviates from it at the higher velocities typical of gas wells, where inertial and turbulent losses become significant. By testing the well at multiple flow rates, engineers can characterize both the laminar permeability response and the turbulent velocity-dependent component, producing a complete picture of the well's ability to deliver gas to the surface at any given back-pressure.

Before testing begins, the well is shut in long enough for bottomhole pressure to stabilize at or near static reservoir pressure. The exact shut-in duration depends on reservoir permeability — tight formations may require days or weeks to reach pseudo-static conditions, while high-permeability zones stabilize in hours. After shut-in, the well is opened to flow at a series of increasing or decreasing rates, each held constant until pressure stabilizes or for a prescribed time interval. The final shut-in pressure after all flow periods completes the data set needed to construct the deliverability curve.

Fast Facts: Deliverability Test

Primary output: Absolute open flow (AOF) and deliverability curve (IPR)
Standard test types: Back-pressure, isochronal, modified isochronal, single-point
Plot type: Log-log of flow rate (Q) vs. pressure-squared differential (Pr² - Pwf²)
Flow equation slope: n = 1 (fully laminar) to n = 0.5 (fully turbulent)
LIT analysis components: a (laminar/Darcy) + b (turbulent/non-Darcy) coefficients
Regulatory use: Sets maximum allowable producing rate (MAPR) in most jurisdictions
Pipeline use: Confirms well can meet contracted delivery pressures and volumes
Retest requirement: Typically required after major workover, stimulation, or zone change

Field Tip:

When conducting a modified isochronal test on a low-permeability well, always run an extended flow period at the end to obtain a single stabilized data point for curve anchoring. Without it, the extrapolated AOF can be optimistic by 20 to 40 percent because the transient data alone does not capture pseudo-steady-state skin effects. Regulators in most jurisdictions require that the stabilized point be used to position the deliverability curve even if the isochronal data defines its slope.

Test Types and When to Use Each

The conventional back-pressure test (also called the flow-after-flow test) flows the well at three or four rates in sequence without returning to shut-in between rates. It requires that each flow rate be sustained until full stabilization, making it appropriate only for high-permeability reservoirs where stabilization occurs within hours. The resulting four-point plot on log-log coordinates yields a straight line; the AOF is read from the intersection of the line with the pressure-squared differential corresponding to atmospheric back-pressure.

The isochronal test was developed for tight reservoirs where full stabilization would take weeks. Each flow rate is held for an equal, short time interval (the isochronal period), followed by a complete shut-in return to static pressure before the next rate. The equal time intervals ensure that transient data points represent the same radius of drainage, making them comparable despite the absence of stabilization. A single extended stabilized flow point at the end anchors the transient curve to realistic deliverability. The modified isochronal test relaxes the requirement for full pressure recovery between flow periods, substituting shorter pseudo-shut-in periods, which saves time but introduces a small correction for incomplete pressure equalization.

AOF Calculation and the Deliverability Curve

The absolute open flow (AOF) is the well's theoretical maximum production rate against zero back-pressure (atmospheric wellhead conditions). It is not an operationally achievable rate — pipelines always impose some minimum delivery pressure — but serves as a normalized index for comparing wells and setting regulatory allowables. AOF is determined by extending the log-log deliverability curve until it intersects the horizontal line representing the pressure-squared differential at atmospheric conditions (approximately 14.65 psia).

The slope of the deliverability curve, denoted n, ranges from 1.0 (purely laminar, Darcy flow) to 0.5 (fully turbulent flow). Most gas wells fall between 0.5 and 1.0, with high-rate wells in permeable formations trending toward 0.5 due to non-Darcy turbulence near the wellbore. LIT analysis separates these components by plotting the pressure-squared differential divided by flow rate against flow rate; the y-intercept gives the laminar coefficient a (related to formation permeability and skin) and the slope gives the turbulent coefficient b (related to inertial resistance and perforation geometry).

Deliverability test is also referred to as:

Back-pressure test — the original term from Rawlins and Schellhardt's 1935 USBM study that established the methodology
Flow test — general field usage; less specific, as it may also refer to a simple single-rate production test
AOF test — emphasizes the absolute open flow determination as the primary goal
Inflow performance test — used when the objective is a full IPR curve rather than just the AOF value

Frequently Asked Questions About Deliverability Tests

Why is the AOF not used as the actual producing rate?

Producing a gas well at its AOF would require zero back-pressure at the wellhead, which is physically impossible because the pipeline system always maintains some positive delivery pressure. AOF is a theoretical benchmark used to compare wells, set regulatory allowables as a fraction of AOF (commonly 1/6 to 1/5 AOF for daily limits), and design compression facilities. Actual producing rates are determined by surface facility pressure and pipeline operating conditions, both of which impose real back-pressure on the wellbore.

How often must deliverability tests be repeated?

Most jurisdictions require an initial deliverability test when the well is completed and thereafter whenever a material change occurs — such as a stimulation treatment, workover, zone perforation or abandonment, or a significant decline in productivity relative to the established curve. Some states also mandate periodic retesting on a fixed schedule (every three to five years) for wells that have not been tested recently, to ensure that allowable rates remain current with actual reservoir deliverability.

What is the difference between a deliverability test and a pressure buildup test?

A deliverability test measures the well's ability to produce at various flowing pressures, generating an IPR curve and AOF value. A pressure buildup (PBU) test measures reservoir properties — permeability, skin damage, and average reservoir pressure — by analyzing the pressure recovery after the well is shut in. Both are forms of well testing, but they answer different questions. A deliverability test answers "how much can this well produce?"; a PBU test answers "what are the reservoir characteristics controlling that production?"

Why Deliverability Tests Matter in Oil and Gas

Deliverability testing provides the quantitative foundation for almost every major decision in gas well development and operation. Pipeline companies require AOF data before committing to gas purchase contracts, because they need assurance the well can sustain contracted volumes over the life of the agreement. Facilities engineers use deliverability curves to size compression, separators, and metering equipment. Reservoir engineers rely on AOF trends to track well performance and diagnose formation damage or fluid loading that reduces productivity. Regulatory agencies use deliverability data to set maximum allowable producing rates that prevent reservoir over-production and protect correlative rights among multiple operators in shared formations. Without reliable deliverability data, gas development decisions rest on guesswork rather than engineering measurement.