Drawdown Test: Pressure Transient Well Testing

What Is a Drawdown Test?

Drawdown test (also called a flow test or producing pressure transient test) is a pressure transient well test in which a well is produced at a controlled, approximately constant rate after a shut-in period has allowed reservoir pressure to equalize, and the decline in bottomhole flowing pressure over time is analyzed to determine reservoir permeability, skin factor, wellbore storage, and reservoir boundaries. The drawdown test is the simplest form of pressure transient analysis and forms the conceptual foundation for more advanced testing methods including buildup tests, interference tests, and pulse tests.

Key Takeaways

A drawdown test requires a well that has been shut in long enough to achieve stable reservoir pressure, followed by production at a constant rate while bottomhole flowing pressure (BHFP) is recorded continuously with a downhole pressure gauge.
During the infinite-acting radial flow period, a semi-log (MDH) plot of BHFP vs. log of producing time yields a straight line whose slope m = 162.6 qBμ/kh, allowing direct calculation of the permeability-thickness product (kh).
Skin factor s is calculated from the semi-log straight line intercept, quantifying near-wellbore damage (positive skin) or stimulation (negative skin from hydraulic fractures or acid jobs).
Buildup tests are generally preferred over drawdown tests in practice because maintaining truly constant rate during a drawdown is difficult, and rate variations create superposition artifacts that complicate analysis; buildup eliminates the production rate control problem by shutting the well in completely.
The Bourdet pressure derivative — the derivative of pressure change with respect to the natural log of time — is plotted alongside pressure change on a log-log diagnostic plot and is the industry standard tool for identifying flow regimes and diagnosing reservoir and wellbore conditions.

How a Drawdown Test Works

Conducting a drawdown test requires first establishing a stable, known reservoir pressure by shutting the well in for a sufficient period — typically several times the expected test duration to ensure the pressure has fully equalized. A calibrated downhole pressure gauge (electronic memory gauge or surface-readout tool) is set at or near the perforations to record bottomhole flowing pressure at intervals of seconds to minutes throughout the test. The well is then opened to production at a controlled, constant rate — typically held constant using a surface choke and verified by continuous surface metering.

As production begins, bottomhole flowing pressure drops as fluid is withdrawn from the near-wellbore region. During the early portion of the test, wellbore storage effects dominate — the expanding wellbore fluid (or changing liquid level in a pumping well) masks the true reservoir response. This early-time period appears as a unit-slope line on the log-log diagnostic plot. As wellbore storage effects diminish, the pressure response transitions to the infinite-acting radial flow period, characterized by the semi-log straight line on the MDH plot and a flat (horizontal) derivative on the log-log plot. If the test continues long enough, late-time boundary effects appear: a fault causes a doubling of the semi-log slope; a closed drainage boundary causes pressure to decline more steeply (pseudo-steady state); a constant pressure boundary (aquifer or gas cap) causes the pressure to stabilize.

Fast Facts: Drawdown Test

Test procedure: Shut in to P_i, produce at constant q, record BHFP vs. time
Key analysis plot: MDH plot: BHFP vs. log(t) — straight line in radial flow period
Semi-log slope: m = 162.6 qBμ / kh (field units)
Permeability from slope: k = 162.6 qBμ / (mh)
Skin from intercept: s = 1.151 [(P_1hr - P_wf) / m - log(k/φμc_t r_w²) + 3.2275]
Diagnostic tool: Bourdet pressure derivative on log-log plot
Wellbore storage: Unit-slope line on early-time log-log plot
Preferred alternative: Pressure buildup test (avoids constant-rate requirement)

Field Tip:

In practice, maintaining truly constant rate during a drawdown test is the primary challenge — surface separator pressure changes, choke plugging, or early water breakthrough all perturb the rate and corrupt the semi-log straight line. Before relying on a drawdown analysis, plot the surface rate vs. time and confirm it is stable within ±5% during the radial flow period. If rate varied significantly, use the superposition time function (equivalent time or Agarwal time) rather than simple producing time to correct the analysis.

Semi-Log Analysis and the MDH Plot

The Miller-Dyes-Hutchinson (MDH) plot is the classical analysis tool for drawdown tests, named after the 1950 paper that formalized the semi-log straight-line approach. Bottomhole flowing pressure is plotted on the y-axis (linear scale) against the log of producing time on the x-axis. During infinite-acting radial flow, this produces a straight line with slope m (in psi/log-cycle). The slope directly yields formation transmissibility: kh = 162.6 qBμ / m, where q is flow rate in STB/day (or MSCF/day for gas), B is formation volume factor, μ is viscosity, and m is the absolute value of the semi-log slope.

The skin factor s is calculated from the y-axis intercept of the semi-log straight line, conventionally read at t = 1 hour (P_1hr). A positive skin indicates near-wellbore damage — drilling mud invasion, clay swelling, scale precipitation, or mechanical restrictions — that creates additional pressure drop around the wellbore beyond what the undamaged formation would produce. A negative skin indicates stimulation: a hydraulic fracture, acid matrix job, or acid fracture has improved near-wellbore conductivity. Typical undamaged skin values range from 0 to 5; severely damaged wells may show skin of 20 to 100 or higher; deeply penetrating hydraulic fractures can produce negative skin values of -3 to -7.

Drawdown vs. Buildup Tests

While the drawdown test is conceptually simpler — the well is merely produced and pressure recorded — buildup tests are the preferred method in most practical applications. In a buildup test, the well is first produced at a known rate, then shut in completely, and the rise in bottomhole pressure is monitored. Shutting the well in completely eliminates the constant-rate requirement that makes drawdowns difficult: surface rate measurement errors, separator fluctuations, and multiphase flow variability all become irrelevant once the well is shut in. Buildup analysis uses the Horner time function — log[(t_p + Δt) / Δt] — rather than simple producing time, where t_p is producing time before shut-in and Δt is shut-in time.

The drawdown test retains practical importance in situations where the cost of deferred production during a prolonged shut-in is prohibitive, in exploration wells where initial reservoir characterization during the first flow period provides critical data, and as the reference test that precedes a buildup. Many operators run a short initial drawdown to establish productivity index and verify completion integrity, then shut the well in for a full buildup analysis. The combined drawdown-buildup sequence, analyzed together using superposition principles, provides richer diagnostic data than either test alone.

Drawdown test is also referred to as:

flow test — general term for any test in which the well is produced; context usually clarifies whether pressure measurement is included
producing pressure transient test — the technically precise term distinguishing it from shut-in (buildup) pressure transient tests
constant-rate drawdown test — specifies that rate is controlled, distinguishing from variable-rate or isochronal tests used for gas well deliverability
MDH test — informal reference to the Miller-Dyes-Hutchinson analysis method applied to drawdown data

Frequently Asked Questions About Drawdown Tests

What is the Bourdet derivative and why is it used?

The Bourdet pressure derivative is the derivative of the pressure change (ΔP) with respect to the natural logarithm of time, plotted on the same log-log scale as ΔP vs. time. It was introduced by Bourdet et al. in 1983 and has since become the standard diagnostic tool in pressure transient analysis. The derivative is extremely sensitive to flow regime changes that are invisible on the pressure curve alone: radial flow appears as a horizontal (constant) derivative; wellbore storage appears as a unit-slope line; a sealing fault appears as a late-time derivative that doubles the radial flow value; linear flow (fractures) appears as a half-slope line; spherical flow (partial penetration) appears as a negative half-slope. Most modern PTA software packages display the Bourdet derivative automatically alongside the pressure change curve on the log-log diagnostic plot.

How long should the pre-test shut-in period be before a drawdown test?

The pre-test shut-in must be long enough to allow pressure to equalize throughout the drainage area to at least the average reservoir pressure. A common rule of thumb is that the shut-in duration should be at least equal to the planned drawdown test duration, and preferably 2 to 5 times longer. For a well with a long prior production history, the shut-in required to fully equalize pressure may be weeks to months — this is the primary reason buildup tests are preferred for transient analysis. If the well cannot be shut in for the full equalization period, the initial pressure used in the analysis must account for the residual pressure gradient, typically using extrapolation from a short buildup or a Horner-corrected initial pressure estimate.

What boundary conditions can be detected from a drawdown test?

Late-time boundary effects appear in the pressure vs. time data once the expanding pressure front reaches the drainage boundary. A single sealing fault causes the semi-log slope to double (the image-well method explains this as two-fold radial flow). A closed drainage boundary causes the derivative to rise steeply (pseudo-steady state — pressure declining linearly with time). A constant-pressure boundary (strong aquifer, gas cap, or injection well maintaining pressure) causes the derivative to drop toward zero as pressure stabilizes. Two intersecting faults (channel reservoir) produce linear flow signatures with a half-slope derivative. Detecting and characterizing these boundaries from transient data is one of the primary objectives of extended well tests in new field appraisal programs.

Why Drawdown Tests Matter in Oil and Gas

Drawdown tests and the pressure transient analysis methods derived from them are fundamental to quantifying reservoir quality, well completion effectiveness, and long-term production potential. The permeability and skin values derived from transient analysis directly determine whether a well is producing at its natural potential or whether a workover, stimulation, or re-completion is warranted. In exploration and appraisal programs, extended drawdown tests in new discoveries provide the reservoir characterization data needed to make billion-dollar development decisions. Despite being one of the oldest tools in the petroleum engineer's toolkit, pressure transient analysis remains indispensable in both conventional and unconventional reservoir development worldwide.