Drillstem Test

A drillstem test (DST) is a well test conducted while the drill string is still in the hole, before the well is cased and completed. By packing off a zone of interest with inflatable packers or mechanically set packers attached to the drill string, the test engineer opens the formation to flow through the drill pipe at surface and then shuts it in to record the pressure buildup. The data collected (flowing pressure, buildup pressure, fluid samples, and wellhead flow rates) tells the geologist and reservoir engineer whether the zone is commercially productive, what the reservoir pressure and permeability are, and what type of fluid (oil, gas, condensate, or water) is present. A DST is the fastest and least expensive way to get direct reservoir data from a new discovery before committing to completion and casing costs.

Key Takeaways

A standard DST has four main periods: an initial flow period (IFP, typically 5 to 30 minutes), an initial shut-in period (ISIP, 30 minutes to 2 hours), a final flow period (FFP, 1 to 8 hours depending on well deliverability), and a final shut-in period (FSIP, equal to or longer than the FFP). The ISIP pressure stabilizes toward the static reservoir pressure and provides a quick estimate of formation pressure. The FSIP buildup curve gives the most complete data for transmissibility (kh/μ) and skin factor calculation.
Downhole electronic gauges (quartz crystal pressure sensors) record pressure to within 0.01 kPa resolution at sample rates of 1 to 10 seconds. This high-resolution data allows the reservoir engineer to apply Horner plot analysis or more advanced derivative analysis (log-log pressure derivative) to identify the flow regime (radial, linear, bilinear) and calculate reservoir transmissibility and skin from the shape of the buildup curve.
A DST is run with the drill string rather than tubing, which means the test must be completed before the well is cased. The drill string provides the flow conduit. The packers (typically a single packer for surface casing tests, or a straddle packer with an upper and lower packer to isolate a specific interval) are run on the drill collars below the main drill string.
Fluid samples collected at surface during a DST are the primary means of characterizing reservoir fluid type before completion. The first recovered fluid from a DST is typically mud filtrate or mud filtrate mixed with formation water. As the test progresses, genuine formation fluid (oil, gas, or water) arrives at surface. The DST report records when clean formation fluid was first observed, the API gravity of the oil, the gas-oil ratio, and the water production if any.
The immediate shut-in pressure (ISIP) measured at the end of the initial flow period is the simplest reservoir pressure indicator from a DST. In a normally pressured reservoir, the ISIP should be close to the hydrostatic gradient pressure for the zone depth. An ISIP well above hydrostatic indicates overpressure; well below indicates depletion or undercompaction.

What Is a Drillstem Test and Why Is It Run?

Imagine you have drilled to the depth you believe holds oil or gas. The mud log shows hydrocarbons. The wireline logs show high resistivity and a good porosity response. But you still do not know what pressure the formation is at, how easily it flows, or whether it actually produces oil, gas, or water in commercial quantities. You know what the formation looks like on the outside (from logs). You need to know what comes out of it when you open it up. That is what a DST does: it opens the formation and measures what flows.

The alternative to a DST is to case the well, perforate it, and then test it as a completed well. That approach costs three to six times more and takes weeks longer. A DST done on the same well before casing costs a fraction of the price and gives most of the same critical information within a few days. In frontier or high-cost drilling environments where every well costs tens of millions of dollars, knowing whether to complete or abandon before committing to completion hardware is a multi-million-dollar decision.

In the conventional oil and gas plays of the Alberta Plains, DSTs have been a standard evaluation technique for every new pool discovery since the 1950s. In unconventional horizontal wells (Montney, Duvernay, Cardium laterals), DSTs are less common because the reservoir quality is characterized from cores and logs, and the productive capacity is evaluated after hydraulic fracturing rather than natural flow. However, DSTs are still used in deep conventional exploration wells in the Foothills and in offshore exploration wells where completion costs are extremely high.

Fast Facts

The Horner plot, the primary graphical method for analyzing pressure buildup data from drillstem tests and production well tests, was published by D.R. Horner in a 1951 paper in the Proceedings of the Third World Petroleum Congress. Horner showed that plotting shut-in pressure against log((tp + dt)/dt), where tp is the producing time and dt is the shut-in time, gives a straight line whose slope (m) is related to the reservoir transmissibility by kh = 162.6 q µ B / m (in field units). The straight-line slope on a Horner plot is still the first quantity a well test analyst extracts from a pressure buildup, 70 years after Horner's publication. The method has been extended to handle boundary effects, non-radial flow regimes, and dual-porosity systems, but the fundamental Horner straight line remains the cornerstone of well test interpretation.

DST Procedure and Equipment

A DST tool string is assembled at the bottom of the drill string before the test interval is reached. The key components from bottom to top are: a perforated anchor pipe (allows formation fluid to enter the drill string), a packer (inflatable or mechanical, set by rotation or weight to seal against the casing or open hole wall), a drill pipe test valve (can be opened and closed from surface by manipulating the string), and a pressure recorder carrier (holds two or more downhole pressure gauges that record continuously throughout the test).

The packer is set at a depth above the zone of interest. When the drill pipe test valve is opened (by lowering the string in rotation), the formation is exposed to the hydrostatic head of the drilling mud plus any formation pressure. If the formation pressure exceeds the hydrostatic mud pressure, formation fluid flows up the drill pipe. If it does not, the well is tight and the test is a "dry test."

The sequence of flow and shut-in periods allows the pressure to stabilize and then build back toward static reservoir pressure during each shut-in. The final shut-in period (FSIP) is the most diagnostic because the reservoir has had the longest time to recover, and the shape of the pressure buildup curve during the FSIP reflects the transmissibility (kh/μ) and the skin factor of the wellbore.

Interpreting DST Results

The key deliverables from a DST are: initial reservoir pressure (from ISIP extrapolation), reservoir transmissibility (kh/μ, from Horner slope), skin factor (from the comparison of actual buildup to the ideal model), and flow capacity (in cubic metres per day at specific surface pressure). These four numbers answer the questions that decide whether a discovery is commercial:

Is the reservoir pressure high enough to sustain flow to surface? A reservoir pressure at 2,000 metres depth should be at least 17 megapascals in a normally pressured formation; below 12 MPa would indicate a depleted or undercompaction zone that may not flow without artificial lift.

Is the transmissibility high enough to sustain commercial rates? A kh product (permeability times reservoir thickness) of 100 mD·m is a rough threshold for a conventional gas well to be commercial without stimulation. Below this, stimulation (fracturing) is needed. Above 1,000 mD·m, the well should flow at commercial rates naturally.

Is the skin positive or negative? A positive skin indicates wellbore damage (drilling fluid invasion, formation damage) that is reducing the well's actual deliverability below its theoretical maximum. A skin of +10 means the well is producing as if the effective wellbore radius is 10 times smaller than the actual wellbore. A negative skin indicates natural fractures or stimulation have enhanced flow beyond the matrix radial flow model.

The drillstem test is universally abbreviated DST in well reports and completion engineering documents. Related terms include Horner plot (the graphical method for analyzing pressure buildup data; a straight-line extrapolation to infinite shut-in time gives the static reservoir pressure, and the slope gives the transmissibility kh/μ), skin factor (a dimensionless number that quantifies wellbore damage or enhancement relative to ideal radial flow; calculated from the difference between actual and theoretical buildup curves in a DST), transmissibility (the product of permeability, reservoir thickness, and reciprocal fluid viscosity, kh/μ; the key reservoir quality parameter extracted from pressure buildup analysis in a DST), packer (the downhole sealing tool that isolates the test interval from the rest of the wellbore during a DST; must hold the pressure differential between the test zone and the wellbore above it), and initial shut-in pressure (ISIP, the pressure recorded at the end of the initial flow period; a quick indicator of whether the formation is overpressured, normally pressured, or depleted).

How a DST Misinterpretation Delayed a Significant Nisku Carbonate Discovery for Two Years

An operator was testing a Devonian Nisku carbonate reef prospect in the Rimbey-Meadowbrook reef chain of central Alberta. The discovery well had good porosity and oil shows on the wireline logs. A DST was run over the main reef interval from 2,840 to 2,865 metres. The initial flow period produced gas and some oil-cut mud. The ISIP was 28.6 megapascals. The final flow period produced gas to the flare but no significant oil to the test tank. The FSIP pressure buildup was short (6 hours) because a surface equipment issue curtailed the test.

The well evaluator interpreted the short FSIP buildup as indicating tight rock: the buildup slope on the Horner plot did not reach a clear semilog straight line in the available data. The skin was estimated at +8, suggesting damage. The reservoir engineer concluded the interval was a tight carbonate that produced only gas because the oil column was too thin to reach the perforations. The recommendation was to not complete the well.

Two years later, an offset operator drilled 3 kilometres away and completed the same Nisku reef interval. Their DST ran a full 24-hour FSIP. The Horner plot showed a clear semilog straight line giving a kh of 380 mD·m, which is excellent for a Nisku carbonate. The gas produced in the first DST was gas cap gas that had migrated to the top of the reef; the oil column sat 15 metres below the original DST perforations. The offset well produced at 350 cubic metres of oil per day on natural flow.

The original operator went back, recompleted their discovery well at the lower interval, and it matched the offset well's productivity. The two-year delay was caused by two errors: a DST perforated in the gas cap rather than the oil column, and a truncated FSIP that did not allow the Horner straight line to develop. The combined value of the two-year production delay was approximately CAD 28 million at the prevailing oil price.