pressure buildup, Oil & Gas Glossary

What Is a Pressure Buildup Test?

A pressure buildup test (BU or PBU) is a pressure transient analysis method in which a producing well is shut in and the rate of pressure recovery in the wellbore is measured over time. Before shut-in, the well produces at a known stabilised rate; at shut-in, the flowing bottomhole pressure begins rising toward static reservoir pressure as the pressure perturbation created by production dissipates radially into the formation. Analysis of this pressure recovery curve using Horner plot, log-log derivative, or numerical methods yields the most important reservoir parameters measurable in the wellbore: static reservoir pressure, formation permeability-thickness product (kh), wellbore skin factor, and drainage area. Pressure buildup tests are the gold standard of well testing — they are more reliable than drawdown tests because any rate measurement errors during the producing period are isolated after shut-in.

Key Takeaways

A pressure buildup test shuts a producing well in and measures the rising wellbore pressure versus time — the rate of pressure recovery reveals permeability, skin, and static reservoir pressure.
The Horner plot (shut-in pressure vs. log[(tp + Δt)/Δt], where tp = producing time and Δt = shut-in time) is the standard analysis method — the straight-line slope m gives kh and skin.
The log-log derivative (d(ΔP)/d(ln Δt)) is the diagnostic standard — flow regime identification from derivative shape precedes quantitative analysis.
Wellbore storage (afterflow) obscures early-time pressure data — the wellbore storage period must end before radial flow can be identified on the log-log derivative.
Static reservoir pressure P* is extrapolated from the Horner straight line to infinite shut-in time — it is the most reliable pressure measurement available without running a gradient survey.

Horner Plot Analysis

The Horner plot plots shut-in bottomhole pressure (BHSP) on the y-axis against the time ratio log[(tp + Δt)/Δt] on the x-axis, where tp is the equivalent producing time before shut-in and Δt is the elapsed shut-in time. During the radial flow period, this plot yields a straight line. The slope m of this line (psi per log cycle) is used to calculate permeability-thickness: kh = 162.6 × q × B × μ / m. The skin factor S is calculated from the pressure difference between the extrapolated straight line and the actual BHSP at Δt = 1 hour: S = 1.151 × [(Pi – Pwf(Δt=1)) / m – log(k / φμctrw²) + 3.2275]. A positive skin indicates near-wellbore damage; negative skin indicates stimulation (a hydraulically fractured well).

The log-log derivative (pressure change and its derivative with respect to the natural log of shut-in time) is plotted alongside the raw buildup data as the primary diagnostic tool. The derivative stabilises at a value of 0.5 × m (where m is the Horner slope) during radial flow — the flat derivative "hump" is the definitive flow regime identifier. Before this stabilisation, unit-slope wellbore storage dominates; after it, boundary effects (declining derivative = closed boundary; rising derivative = constant pressure boundary or heterogeneity) appear.

Fast Facts: Pressure Buildup Test

Well condition: well shut in after stabilised production at rate q
Standard analysis: Horner plot (semi-log), log-log derivative diagnostic
Key outputs: kh, skin S, static pressure P*, drainage area
Flow regime sequence: wellbore storage → radial flow → boundary effects
Radial flow identifier: flat derivative at value = m/2 on log-log plot
Minimum test duration: radial flow period must last at least one log cycle of Δt
Regulatory reporting: many jurisdictions (AER, BSEE, NOD) require pressure test results
Analogous tests: fall-off test (injection well equivalent of buildup test)

Well Test Operations Tip:

Ensure wellbore storage ends before attempting Horner analysis — if the unit-slope wellbore storage period masks the radial flow period, the Horner straight line will be incorrectly identified, giving wrong permeability and skin. Calculate the expected end of wellbore storage: Δtws ≈ (200,000 + 12,000 × S) × C / (kh), where C is the wellbore storage coefficient (bbl/psi). For high-skin, high-storage wells, the radial flow regime may not appear until hours or days into the shut-in. A short buildup test (2–4 hours) on a damaged well with a large liquid column in the wellbore may provide nothing useful. Design test duration from the wellbore storage calculation before running the test — not after.

Pressure buildup test is also referred to as:

BU test / PBU test — standard abbreviations used in well test reports
Shut-in test — operational description of the test procedure
Horner test — named after the analysis method, used loosely to mean a pressure buildup
Fall-off test — the injection-well equivalent: injection stopped, pressure falls off toward static pressure; analysed by identical methods

Frequently Asked Questions About Pressure Buildup Tests

How long does a pressure buildup test need to run?

Test duration must be long enough to reach radial flow — the flow regime from which permeability and skin are extracted. The minimum radial flow duration is typically one log cycle of shut-in time (e.g., if radial flow begins at Δt = 2 hours, the test should run to at least Δt = 20 hours to span one cycle on the Horner plot). For boundary detection (drainage area, fault location), the test must run long enough to see boundary effects on the log-log derivative — typically 2–5× the time to the nearest boundary. Well testing service companies run predictive simulations using prior permeability estimates to design minimum test durations before the gauge is run into the hole.

What is the difference between static pressure and average reservoir pressure?

Static pressure P* extrapolated from the Horner plot is the pressure at the well's virtual drainage boundary — it equals the volumetric average reservoir pressure only for a well at the centre of a closed circular drainage area. In a field with multiple wells, each well's Horner P* represents the average pressure in that well's drainage area, not the field average. The Matthews-Brons-Hazebroek (MBH) method corrects P* for actual well position within the drainage boundary. Average reservoir pressure from MBH is the input to material balance calculations. Using uncorrected P* values as field-average pressure in material balance calculations systematically overestimates reservoir energy and underestimates depletion.

Can a pressure buildup test identify hydraulic fracture properties?

Yes. In a hydraulically fractured well, the log-log derivative shows a half-slope straight line (slope = 0.5) during bilinear or linear flow from the fracture before radial flow begins. Bilinear flow (slope = 0.25) reflects simultaneous flow through the fracture and from the formation into the fracture. From these early-time flow regimes, fracture half-length (xf) and fracture conductivity (FcD) can be estimated — parameters not accessible from radial flow analysis alone. In tight gas and shale oil wells where radial flow never develops during a practical test duration, fracture parameter analysis from early-time buildup data is the only quantitative well characterisation available from a pressure test.

Why Pressure Buildup Tests Matter in Oil and Gas

Pressure buildup testing is the most rigorous method available for measuring in-situ reservoir permeability, quantifying wellbore damage, determining static pressure, and characterising drainage boundaries — all without coring or logging. Every major production decision — stimulation design, well spacing, facility sizing, reserve certification — depends at some stage on pressure transient data. In regulatory environments (AER in Alberta, BSEE offshore USA, the Petroleum Safety Authority in Norway), periodic pressure buildup tests are mandatory on producing wells to demonstrate reservoir management and support reserve reporting. A well test programme is a small investment relative to the drilling and completion cost, but the data it generates informs decisions worth orders of magnitude more.

Pressure Buildup Test: Definition, Well Testing, and Reservoir Analysis