Pressure Falloff: Injection-Well Transient Testing, Horner Analysis, and AER Directive 051 Disposal Compliance
Pressure falloff is the decline in bottomhole pressure that occurs after injection into a well is stopped or sharply reduced. It is the injection-well counterpart to the pressure buildup observed when a producing well is shut in, and the two are governed by the same diffusivity physics, simply with the sign of the flow reversed. During injection, fluid is forced into the formation and the wellbore pressure is held above reservoir pressure; when the pump is shut down, that excess pressure bleeds off into the surrounding rock and the measured pressure falls along a curve whose shape encodes the properties of the reservoir and the condition of the wellbore. Engineers run a pressure falloff test by injecting at a constant, stabilized rate for a known period, then shutting in and recording the falling pressure with a high-resolution downhole gauge over hours to days. Analysis of that decline yields the effective permeability-thickness product (kh), the near-wellbore skin factor that quantifies damage or stimulation, and an extrapolated estimate of the average reservoir pressure. The classic interpretation uses a Horner plot, a semilog graph of pressure against the Horner time ratio (tp plus delta-t) divided by delta-t, where the slope of the straight-line radial-flow section gives kh and the extrapolation to a Horner time of one yields the reservoir pressure P-star. Modern practice augments the Horner method with log-log diagnostic plots of pressure and its derivative, which reveal flow regimes such as wellbore storage, radial flow, boundaries, and induced fractures. In the Western Canadian Sedimentary Basin, falloff testing is central to the management of water and acid-gas disposal wells and to SAGD steam and CO2 injection projects, because it confirms the injected fluid is staying within the permitted zone and that injection pressure remains below the formation fracture pressure. The Alberta Energy Regulator addresses injection and disposal wells under AER Directive 051, with pressure and deliverability testing methods set out in Directive 040, and operators schedule periodic falloff surveys to demonstrate continued containment and to update the reservoir pressure used in their maximum-injection-pressure calculations.
Key Takeaways
- The injection-well mirror of buildup: A pressure falloff test shuts in an injector after stabilized injection and records the declining pressure, exactly analogous to shutting in a producer for a buildup. The same diffusivity equation applies, so the same analytical tools, Horner plots and derivative diagnostics, resolve permeability, skin, and reservoir pressure from the falling curve.
- Horner plot yields kh and P-star: Plotting pressure against the Horner time ratio (tp + delta-t)/delta-t produces a straight radial-flow line whose slope m gives the permeability-thickness product through kh = 162.6 q B mu / m in field units. Extrapolating that line to a Horner time of one estimates the average reservoir pressure P-star at infinite shut-in time.
- Skin separates damage from stimulation: The falloff analysis returns a skin factor; a positive skin indicates near-wellbore plugging that raises injection pressure for a given rate, while a negative skin reflects stimulation such as an acid treatment or an induced fracture. Disposal operators watch skin trends over successive tests to catch progressive plugging before it forces a workover.
- Containment and pressure compliance: Under AER Directive 051, disposal and injection wells must demonstrate that fluid stays in the approved interval and that injection pressure does not exceed the limit derived from the formation fracture pressure. Falloff-derived reservoir pressure feeds directly into the maximum-allowed wellhead injection pressure calculation, making the test a compliance instrument as well as a reservoir tool.
- Derivative diagnostics reveal boundaries: The log-log pressure-derivative plot exposes flow regimes the Horner plot alone can miss, including wellbore storage early in the test, infinite-acting radial flow, sealing faults, and the half-slope signature of an induced fracture. For acid-gas and CO2 injectors, detecting a fracture signature is critical because it can signal loss of containment.
Running a Falloff on a WCSB Disposal Well
A typical produced-water disposal well in central Alberta injects into a saline aquifer such as a Mannville or basal Cambrian sand. The operator first injects at a steady rate, perhaps 200 to 400 m3/d, long enough to stabilize the pressure field, then shuts in with a memory gauge or surface-read gauge across the perforations. The falloff is recorded until radial flow is clearly established, often 24 to 72 hours depending on permeability. Low-permeability zones need longer shut-ins to develop the straight Horner line, and wellbore storage early in the test can mask the first hours, so gauge resolution and adequate test duration are planned in advance to avoid an uninterpretable result.
From Falloff Pressure to Maximum Injection Pressure
The reservoir pressure extracted from a falloff test is not academic; it sets the operating envelope. The maximum permitted injection pressure is tied to the formation fracture pressure, and the safe margin depends on knowing the current average reservoir pressure, which rises over the life of a disposal well as cumulative volume accumulates. A falloff conducted every nine to fifteen months tracks that rising pressure and lets the operator confirm injection stays below the fracture threshold. If the test shows reservoir pressure climbing toward the limit, the operator may reduce rate, add disposal capacity, or evaluate a second zone before containment is ever at risk.
Fast Facts
The Horner plot that anchors falloff analysis was published by D. R. Horner in 1951, and more than seven decades later its straight-line extrapolation remains the reference method written into regulatory testing guidelines on both sides of the border. What began as a graphical trick for reading reservoir pressure off semilog paper now runs inside automated pressure-transient software, yet regulators still require the underlying Horner straight line to be demonstrable, because its simplicity makes a disposal-well containment claim auditable by any reviewer.
Related Terms
Pressure falloff is the injection-side analogue of pressure buildup, sharing its math and its diagnostic plots. Both are forms of pressure transient analysis, the discipline that infers reservoir properties from time-varying pressure. The tests resolve the near-wellbore skin factor that flags damage or stimulation, and falloff is indispensable to injection well surveillance, where confirming containment and pressure compliance is a regulatory obligation.
Real-World WCSB Scenario
An operator running a produced-water disposal well near Lloydminster injects 300 m3/d into a Mannville sand and conducts a scheduled falloff test to satisfy AER Directive 051 surveillance. The Horner plot returns kh consistent with a permeability of about 250 mD over a 12 m net interval and a skin of plus 3, indicating mild near-wellbore plugging, while P-star shows reservoir pressure has risen 1,100 kPa over two years of disposal. The test program, including gauge rental and a 48-hour shut-in, costs roughly CAD 35,000.
With the updated reservoir pressure, the operator recalculates the maximum injection pressure, confirms a comfortable margin below the fracture threshold, and schedules a small acid treatment to remove the skin and restore injectivity. The falloff data both keeps the well compliant and defers a far costlier capacity expansion.