pressure buildup analysis, Oil & Gas Glossary

What Is Pressure Buildup Analysis?

Pressure buildup analysis (also called a buildup test or PBU test) is a well testing technique in which a producing well is shut in after a stabilized production period and the subsequent rise in bottomhole pressure is recorded and interpreted to determine reservoir transmissibility (kh/mu), skin factor, average reservoir pressure, and boundary conditions. The technique relies on superposition theory: shutting in the well is mathematically equivalent to adding an imaginary injection well at the same location, which causes the wellbore pressure to recover along a predictable logarithmic trend that reveals rock and fluid properties between the well and the drainage boundary.

Key Takeaways

A buildup test shuts in a producing well and measures the bottomhole pressure recovery over time to back-calculate permeability, skin, and reservoir pressure.
The Horner plot (pressure vs. log of the Horner time ratio) produces a straight line whose slope gives reservoir transmissibility (kh/mu) directly.
Skin factor measures near-wellbore damage or stimulation; a positive skin indicates damage, a negative skin indicates stimulation such as hydraulic fracturing.
Pressure derivative analysis on a log-log plot identifies distinct flow regimes: wellbore storage, radial flow (the flat 0.5-line), and boundary effects.
Buildup tests are the primary tool for validating perforated interval quality, confirming hydraulic fracture effectiveness, and estimating average reservoir pressure for material balance.

How Pressure Buildup Analysis Works

Before shut-in, the well must be produced at a stabilized rate for a period long enough to establish radial flow in the reservoir. At shut-in time, downhole gauges (typically quartz or strain-gauge pressure recorders with resolution of 0.01 psi or better) begin logging the pressure recovery at high frequency, often every few seconds. The producing time before shut-in is denoted tp and the elapsed shut-in time is dt. The Horner time ratio is (tp + dt)/dt. When bottomhole shut-in pressure (BHSP) is plotted on the y-axis against the log of the Horner ratio on the x-axis, the data fall on a straight line during the period of radial flow. The slope of this line, m, in psi/cycle gives formation transmissibility: kh = 162.6 qBmu / m, where q is the production rate in STB/d, B is the formation volume factor, and mu is viscosity. Rearranging for permeability when net pay h is known yields average effective permeability to the flowing phase.

Skin factor S is calculated from the pressure at one hour of shut-in on the Horner straight line (P1hr), the slope m, porosity, viscosity, total compressibility, and wellbore radius: S = 1.1513[(P1hr - Pwf) / m - log(k / phi mu ct rw^2) + 3.2275]. For wells that have been producing long relative to the shut-in time, the Miller-Dyes-Hutchinson (MDH) plot of pressure versus log(dt) substitutes for the Horner plot and avoids uncertainty in choosing an equivalent producing time. Modern analysis uses the pressure derivative, defined as the change in pressure per unit change in the natural log of shut-in time, plotted on a log-log diagnostic plot alongside the pressure change itself. Wellbore storage appears as a unit-slope line at early time. Radial flow appears as a flat derivative at 0.5 (on the Bourdet derivative). Hydraulic fracture bilinear flow gives a half-slope on the derivative, and linear fracture flow gives a quarter-slope. These signatures allow identification of the correct analysis window before fitting the Horner straight line.

Boundary effects appear at late time on the buildup. A single sealing fault causes the derivative slope to double (from 0.5 to 1.0), indicating that the apparent transmissibility is halved by image well interference. A closed circular reservoir drives the derivative to a unit slope on log-log coordinates, confirming depletion. Extrapolating the Horner straight line to infinite shut-in time (Horner ratio = 1) gives the false pressure P*, which approximates initial reservoir pressure in a virgin system. In a depleted reservoir, P* overestimates average pressure and a Matthews-Brons-Hazebroek (MBH) correction is applied to obtain true average drainage-area pressure.

Fast Facts: Pressure Buildup Analysis

Test type: Transient well test, shut-in after production
Key diagnostic plot: Horner plot (BHSP vs. log[(tp+dt)/dt])
Slope unit: psi per log cycle (psi/cycle)
Transmissibility formula: kh = 162.6 qBmu / m
Radial flow signature: Derivative flat at 0.5 on log-log plot
Wellbore storage signature: Unit slope on log-log diagnostic
Fault detection: Derivative slope doubles (from 0.5 to 1.0)
Average pressure method: P* extrapolation with MBH correction

Field Tip:

Always record the production rate and cumulative production in the hours immediately before shut-in. Rate variation in the last few hours before shut-in introduces superposition error that distorts the early-time Horner straight line. If the rate was not stabilized, use multi-rate superposition or equivalent producing time corrections before interpreting the slope. A portable downhole gauge run on slickline will give more accurate BHSP data than surface pressure corrected for a fluid column, particularly in gassy wells where the gradient changes with gas breakout.

Pressure Derivative and Modern Diagnostic Methods

The Bourdet pressure derivative transformed buildup analysis from a single straight-line method into a multi-regime diagnostic tool. By plotting both the pressure change (dP) and its logarithmic derivative (dP/d ln dt) on a single log-log graph, engineers can identify wellbore storage, fracture geometry, radial flow, and boundary effects at a glance before committing to a specific model. Commercial software packages such as Kappa Ecrin, Saphir, and IHS Harmony automate derivative computation using Bourdet smoothing coefficients (L values typically 0.1 to 0.3) and allow simultaneous history matching of the pressure and derivative with a reservoir model that may include fractures, composite zones, or arbitrary boundary shapes.

Unconventional wells rarely exhibit classical radial flow during a practical shut-in period because the effective permeability is so low (microdarcy to nanodarcy range) that the pressure transient has not reached a radial flow regime even after weeks of shut-in. In these wells, buildup analysis focuses on fracture linear flow (half-slope derivative) and compound linear flow, extracting fracture half-length and stimulated reservoir volume (SRV) estimates rather than matrix permeability directly. Diagnostic plots from multiple buildup tests across a horizontal well lateral can map SRV heterogeneity and identify stages that underperformed stimulation targets.

buildup test: common field abbreviation for a pressure buildup analysis
PBU test: abbreviated form used in well test reports and AFE documents
shut-in test: informal term emphasizing the mechanical operation of closing the well in
Horner analysis: refers specifically to the straight-line plotting method introduced by D.R. Horner in 1951

Frequently Asked Questions About Pressure Buildup Analysis

How long does a pressure buildup test need to run?

The shut-in duration depends on reservoir permeability and the information sought. In a 100 md conventional reservoir, radial flow may be reached within minutes, and a 6-hour buildup captures both radial flow and nearby boundaries. In a tight gas well with 0.01 md permeability, radial flow may require weeks or months to develop. As a practical rule, the shut-in time should equal or exceed the producing time (tp) to allow full pressure recovery to near-static conditions, but in high-productivity wells this is often impractical. Modern numerical simulation allows partial recovery to be matched to a full reservoir model without requiring complete pressure equalization.

What is the difference between a buildup test and a drawdown test?

A drawdown test begins with the well at static reservoir pressure and measures the pressure decline as the well is produced at a controlled rate. A buildup test begins after production and measures the pressure recovery after shut-in. Drawdown tests are more difficult to execute at truly constant rate and are sensitive to rate variations, so buildup tests are preferred for transmissibility and skin determination in most field operations. However, drawdown tests are required to estimate productivity index and to characterize very tight formations where a buildup test would take impractically long to reach radial flow.

Can a pressure buildup test confirm hydraulic fracture half-length?

Yes, but with important caveats. The fracture linear flow regime (half-slope on the log-log derivative) allows calculation of the product of fracture half-length (xf) and square root of fracture conductivity. Separating these two parameters requires bilinear flow data (quarter-slope) or independent knowledge of proppant pack conductivity. In practice, estimated fracture half-lengths from buildup analysis often differ from fracture models by 30 to 50 percent because near-wellbore tortuosity, proppant embedment, and closure stress are not captured in simple analytical models. Combining buildup analysis with microseismic mapping provides more reliable fracture geometry estimates.

Why Pressure Buildup Analysis Matters in Oil and Gas

Pressure buildup analysis is one of the few direct methods available to measure in-situ reservoir permeability, skin damage, and average reservoir pressure without drilling additional wells. These three parameters directly govern production rate, stimulation design, and ultimate recovery estimates. A well with a high positive skin may warrant a workover or re-perforation that pays out in weeks. Average reservoir pressure from multiple wells allows reservoir engineers to calibrate material balance models and predict when a pressure maintenance program such as waterflooding or gas injection will be needed. In regulatory and financing contexts, buildup test results provide independent validation of the permeability and reserves assumptions underlying field development plans, making them a standard requirement for field appraisal programs and reserve certification by independent engineers.

Pressure Buildup Analysis: Reservoir Transmissibility and Skin from Shut-In Tests