falloff test, Oil & Gas Glossary

What Is a Falloff Test?

Falloff test (also called an injection well pressure falloff test or injectivity falloff test) is a pressure transient test conducted on an injection well by shutting the well in after a period of steady injection, then recording the rise in bottomhole pressure (BHP) over time as the injection-induced pressure disturbance dissipates back into the surrounding formation. The falloff test is the injection-well analog of the pressure buildup test performed on producing wells, and it provides the same fundamental reservoir information: formation permeability, wellbore skin factor, average reservoir pressure, and the hydraulic characteristics of the injected fluid bank surrounding the wellbore.

Key Takeaways

The falloff test is conducted by shutting in an injection well after stable injection and measuring the pressure rise at bottomhole as the over-pressured zone around the injector dissipates into the reservoir.
Analysis uses the Horner method adapted for injection by substituting injection rate for production rate and injection time for producing time, yielding permeability and skin from the semi-log straight line.
The presence of a cooled, altered zone near the injector and a mobility contrast between injected fluid and reservoir fluid complicates interpretation compared to standard buildup tests.
In waterflood operations, falloff tests track the advance of the flood front and monitor changes in injectivity over time, providing early warning of formation plugging or fracture extension.
U.S. EPA Underground Injection Control (UIC) regulations require periodic pressure falloff or step-rate tests on Class II and Class VI disposal and sequestration wells to demonstrate mechanical integrity and confirm injection zone confinement.

How a Falloff Test Works

A falloff test begins with a period of injection at a stable, measured surface or downhole rate. The injection duration must be long enough for a pressure transient to propagate well into the undisturbed formation beyond the near-wellbore altered zone. Typical injection periods range from several hours in high-permeability formations to multiple days in tight reservoirs. Continuous bottomhole pressure recording using electronic gauges or surface-read downhole memory gauges captures the injection-period pressure profile.

At shut-in, injection ceases and pressure begins to rise as the over-pressured fluid bank equilibrates radially outward. The falloff period is recorded at the same sampling frequency as the injection period. The fundamental analysis uses the Horner time ratio, expressed as (t_p + Δt)/Δt, where t_p is the injection time and Δt is the shut-in elapsed time. Plotting BHP versus the Horner time ratio on a semi-log scale yields a straight line whose slope m is used to calculate formation permeability (k = 162.6 qμB / mh) and whose extrapolated value at infinite shut-in time approximates the initial or average reservoir pressure.

Skin factor is calculated from the deviation of the actual pressure at a reference shut-in time from the straight line extrapolation, analogous to buildup test skin analysis. Positive skin indicates near-wellbore damage (formation plugging, filter cake), while negative skin can indicate stimulation or open natural fractures. The Hall plot, which plots cumulative injected volume against cumulative injection pressure-time product, is a complementary tool for monitoring long-term injectivity trends without requiring shut-in.

Fast Facts: Falloff Test

Well type: Injection wells (water, gas, CO2, produced water disposal)
Analog: Equivalent to pressure buildup test on producing wells
Primary analysis method: Horner semi-log plot using injection equivalent time
Parameters derived: Permeability (k), skin (S), average reservoir pressure (P*)
Regulatory mandate: EPA UIC Class II (disposal wells), Class VI (CO2 sequestration)
Typical test duration: 24-72 hours shut-in after stable injection period
Pressure measurement: Bottomhole electronic gauges or surface-read memory tools
Waterflood application: Monitors flood front advance and injectivity impairment

Field Tip:

Before a falloff test, inject at a stable, constant rate for at least the same duration as the planned falloff period. Rate variation during the injection period smears the pressure derivative and can obscure the correct semi-log straight line. If rate stabilization is impractical, use superposition time (equivalent time) in the analysis rather than the simple Horner ratio to account for rate history.

Differences from Pressure Buildup Tests

While the mathematical framework is analogous, falloff tests present several complications not encountered in standard buildup analysis on producing wells. The near-wellbore region around an injector is typically cooled below reservoir temperature by the injected fluid, altering fluid viscosity and rock mechanical properties in the invaded zone. Water injection into an oil reservoir creates a region of high water saturation and consequently different fluid mobility around the wellbore. Because effective permeability to water in the water-swept zone differs from the formation permeability to oil in the unswept zone, the falloff response reflects a composite system with an apparent mobility that is neither the injected-fluid mobility alone nor the formation-fluid mobility alone.

The mobility ratio between injected and in-situ fluids creates a mobility contrast that manifests on the pressure derivative as an apparent change in reservoir properties. In favorable mobility ratio floods (water displacing oil of similar viscosity), this effect is minor. In CO2 injection or polymer floods, where the injected fluid has a viscosity much lower or higher than the reservoir oil, the composite system behavior can be pronounced and must be accounted for in interpretation. Specialized composite reservoir models, available in modern pressure transient analysis software such as Ecrin (Kappa Engineering), IHS Harmony, or Saphir, handle these multi-mobility systems explicitly.

Application in Waterflood Monitoring and CO2 Injection

In mature waterflood operations, periodic falloff tests on injectors are a primary surveillance tool. The skin derived from successive tests reveals whether formation damage is accumulating, typically due to suspended solids, bacterial growth, or scale deposition in the perforations and near-wellbore matrix. An increasing positive skin trend triggers well intervention before injectivity falls to levels that compromise voidage replacement and reservoir pressure support. Conversely, a sudden decrease in apparent skin may indicate that injection pressures have exceeded the formation fracture pressure, opening a fracture that short-circuits the flood pattern and bypasses oil.

For CO2 sequestration under EPA UIC Class VI regulations, pressure falloff tests are a key component of the Area of Review (AOR) geomechanical evaluation. The test verifies that injection pressures remain below fracture pressure thresholds and confirms that the CO2 plume has not migrated beyond the approved injection zone. Long-duration falloff tests on Class VI wells are analyzed with multi-phase compositional pressure transient models because the CO2-brine system undergoes phase change as pressure declines during shut-in. Regulatory agencies require these tests at defined intervals (typically annually or following any significant operational change) as part of the site characterization and monitoring plan.

Falloff test is also referred to as:

Pressure falloff test — the most common formal designation in regulatory and engineering documentation
Injection well buildup test — used by analogy with producing well terminology; technically imprecise since pressure is rising, not building up from depletion
Injectivity falloff — emphasizes the connection between the test result and the injectivity index of the well

Frequently Asked Questions About Falloff Tests

How long must an injection well be shut in for a valid falloff test?

As a practical minimum, the shut-in duration should equal the injection period (one log cycle rule). For regulatory purposes, EPA UIC guidelines generally require shut-in until the pressure either stabilizes at a measurable static gradient or the pressure derivative has clearly identified the semi-log straight line on a log-log diagnostic plot. In tight formations with permeability below 1 millidarcy, falloff tests may require multiple days to days of shut-in. High-permeability water disposal formations may reach pseudo-steady state in hours. The engineer designs the test duration by forward modeling using estimated formation parameters before the test.

What is the difference between a falloff test and a step-rate test?

A step-rate test is conducted while injecting, by incrementally increasing injection rate in steps and recording the stabilized bottomhole pressure at each rate. The slope change on a pressure versus injection rate plot identifies the formation parting pressure (fracture extension pressure). A falloff test is conducted after shut-in and characterizes formation properties and skin. Both tests are often conducted in sequence on a new disposal well: the step-rate test establishes the safe maximum injection pressure, and the falloff test establishes baseline permeability and skin against which future tests are compared.

Can a falloff test detect a leak in the injection well casing?

Yes. Mechanical integrity testing (MIT) is a component of EPA UIC compliance for Class II wells, and pressure falloff behavior can reveal annular pressure communication indicating a casing or tubing leak. A falloff test showing an anomalously fast pressure decline or a derivative that does not develop the expected semi-log straight line may suggest fluid is escaping the well through an unintended pathway. However, dedicated mechanical integrity tests, either a static fluid level test or a tubing-casing annulus pressure test, are typically used alongside or in preference to falloff analysis for leak detection.

Why Falloff Tests Matter in Oil and Gas

Falloff tests are the primary quantitative diagnostic tool for injection well performance, providing permeability and skin data that cannot be obtained any other way once a well is on injection. They protect reservoir management by detecting injectivity decline before it impairs sweep efficiency, and they satisfy regulatory requirements that protect groundwater resources from subsurface fluid migration. In enhanced oil recovery and carbon sequestration projects, where the economics and environmental performance of the entire operation depend on reliable injection into the target zone, the falloff test is an indispensable surveillance instrument.