DST Pressure Chart | Oil Authority

The DST pressure chart is the continuous record of downhole pressure versus time produced by recording gauges in a drill stem test (DST) tool. As the tool is run into the hole, pressure increases steadily with depth as the hydrostatic column of mud grows. Once the tool reaches the test interval and the packers are set, the chart captures a structured sequence of flow periods and shut-in pressure buildups that encode the reservoir's permeability, skin, initial pressure, fluid type, and communication boundaries. Interpreting the DST pressure chart correctly is one of the foundational skills in well testing and formation evaluation, providing the only direct measurement of dynamic reservoir properties before a well is completed.

The Pressure Sequence from Surface to Formation

Before any flow begins, the pressure chart records two distinct phases during the trip into the hole. From surface to the casing shoe, pressure rises in proportion to the mud weight and increasing depth. Below the shoe and inside the open-hole or perforated interval, the same hydrostatic relationship continues until the tool reaches bottom. When the DST tool assembly, including the packer, perforated anchor, tester valve, and pressure gauges, lands at the test depth and the packer is inflated and set, the chart shows a brief pressure plateau as the tool mechanically stabilizes. This pre-flow period establishes the mud-column hydrostatic reference, which the analyst uses to confirm that the gauge is recording correctly and that no tool leak has occurred. A gauge that does not reach the expected hydrostatic pressure at total depth signals a tool malfunction, packer failure, or a high-pressure zone above the packer that needs investigation before opening the tester valve.

Initial Shut-in Pressure and Flow Period Sequence

When the tester valve is opened for the first flow period (IFP, initial flow period), pressure drops rapidly as formation fluids enter the drill string and the mud hydrostatic is replaced by a lighter fluid column. The initial shut-in pressure (ISIP) recorded before this first flow period represents the static formation pressure if the tool was not previously opened, or a near-static condition after any prior equalization. The first flow period is typically short, 30 minutes to a few hours, and is used to clean up wellbore mud filtrate invasion and establish whether the zone will produce at all. During flow, surface personnel observe fluid at the surface or monitor the drill string pressure response for evidence of gas cut, oil, water, or salt water. After the first flow period the tester valve is closed, initiating the first shut-in period (ISIP 1) during which reservoir pressure rebuilds. The pressure buildup rate during ISIP 1 begins the diagnostic record of reservoir transmissibility. A second, longer flow period (MFP, main flow period) follows, typically one to several hours for exploration wells, after which the tester valve is closed for the final shut-in period (FSIP), which provides the cleanest pressure buildup data and the most reliable estimate of static reservoir pressure.

Horner Analysis of Shut-in Pressure Buildups

The pressure buildup sequences captured on the DST chart are analyzed using the Horner method, in which shut-in pressure is plotted against the Horner time ratio: (tp plus delta-t) divided by delta-t, where tp is the flow period duration and delta-t is elapsed shut-in time. On a Horner plot, the buildup data fall on a straight line whose slope is proportional to the product of reservoir transmissibility (permeability times thickness divided by viscosity). The slope m in psi per log cycle is used to calculate effective permeability to the flowing fluid. Extrapolating the straight line to the Horner ratio of 1 (representing infinite shut-in time) gives the initial reservoir pressure p*, which equals the true static formation pressure in an infinite-acting reservoir that has not been significantly depleted. The difference between the measured FSIP and the extrapolated p* indicates the degree of pressure depletion or the presence of a nearby boundary. Skin factor s, the dimensionless measure of near-wellbore damage or stimulation, is calculated from the difference between the pressure at one hour on the Horner straight line and the extrapolated initial pressure, corrected for the slope and for reservoir and fluid properties.

Diagnostic Signatures: Gas Kicks, Lost Circulation, and Boundaries

An experienced interpreter reads the DST chart shape to identify reservoir conditions and wellbore events that cannot be seen from surface alone. A sharp pressure spike during the flow period, followed by a rapid pressure decline, indicates a gas kick entering the drill string: the compressed gas expands as it rises, lightening the fluid column and causing a transient surface pressure surge. A straight-line pressure increase during a supposed shut-in period, rather than the concave-upward buildup curve expected from a radial flow system, may indicate that the packer is leaking and that mud hydrostatic is recharging the gauge from above. Lost circulation during the trip in shows as a pressure anomaly where the measured pressure falls below the expected hydrostatic gradient, indicating mud loss to a thief zone. A pressure buildup that stabilizes at a pressure well below the expected formation pressure signals either a small reservoir volume, a tight boundary close to the wellbore, or significant depletion from nearby producing wells. Conversely, a buildup that rises above the mud hydrostatic pressure confirms that the zone is overpressured, which has immediate implications for mud weight adjustments and well control planning.

Mechanical and Memory Gauge Recording

The quality of a DST pressure chart depends entirely on the recording gauge technology used. The oldest and still-common method uses a mechanical Bourdon-tube gauge that scribes a pressure-time trace on a rotating metal or paper chart. Mechanical gauges are robust and require no batteries, but their resolution is limited to roughly 5 to 10 psi and their time resolution is determined by the chart rotation speed, typically 24 hours per rotation. Modern DST operations increasingly use electronic memory gauges, which sample pressure and temperature at intervals as short as one second and store thousands of data points in solid-state memory for download after the test. Memory gauges achieve resolution below 0.1 psi and can detect subtle pressure transients such as wellbore storage distortion, near-wellbore heterogeneity, and dual-porosity behavior in naturally fractured reservoirs that are invisible on mechanical charts. When multiple gauges are run in tandem, one above and one below the packer, the analyst can identify packer bypass and calculate a more accurate fluid gradient in the drill string. The pressure-temperature trace from memory gauges also provides the flowing bottomhole temperature, which is used in fluid PVT correlations and in Joule-Thomson cooling calculations for gas wells.

Key Takeaways

The DST pressure chart records the full sequence of hydrostatic buildup during the trip in hole, packer setting, initial and main flow periods, and shut-in pressure buildups, encoding reservoir permeability, skin, initial pressure, and boundary conditions in a single continuous record.
Horner analysis of the shut-in pressure buildup data calculates effective permeability, skin factor, and extrapolated static formation pressure from the slope and intercept of the straight-line portion of the buildup curve.
Chart shape diagnostics identify gas kicks, packer leaks, lost circulation zones, overpressured intervals, and reservoir boundaries from characteristic pressure signatures during flow and shut-in periods.
Electronic memory gauges with sub-0.1 psi resolution and one-second sampling have largely replaced mechanical Bourdon-tube gauges in modern DST operations, enabling detection of dual-porosity behavior and wellbore storage effects that mechanical gauges cannot resolve.
The final shut-in pressure (FSIP) buildup provides the cleanest and most reliable estimate of static formation pressure and is the primary data source for reservoir characterization and completion design decisions.