Constant Pressure Analysis Chart

How to Actually Use a Constant Pressure Analysis Chart Without Wasting Three Days

A constant pressure analysis chart is a type of pressure transient analysis tool used in reservoir engineering to interpret well test data from tests conducted under stabilized or controlled pressure conditions. It plots dimensionless pressure and its derivative against dimensionless time, allowing you to identify flow regimes, estimate skin factor, and calculate permeability-thickness products from buildup or drawdown tests where the pressure response is measured at near-constant wellbore conditions. The chart itself looks deceptively simple. You have a log-log plot with multiple type curves. The main curve is the dimensionless pressure response. Below it, often offset for clarity, is the derivative curve. During a constant pressure test, the dimensionless pressure quickly approaches unity and then stays flat while the derivative drops. That downward-sloping derivative is where most of the information lives, and it is where people consistently misread the plot.

Reading a Constant Pressure Analysis Chart Correctly

Here is the actual workflow. Run your test through your preferred analysis software and pull the pressure data along with the time and flow rate records. Convert your data to dimensionless form. For the dimensionless pressure, you use the standard form pD that relates the actual pressure drop to the flow rate, viscosity, formation volume factor, permeability, and thickness. For dimensionless time, you apply the standard tD equation using the same parameters plus porosity, total compressibility, wellbore radius, and the actual elapsed time. Overlay your field data onto the type curve. Match the early-time portion first, which shows the wellbore storage effect. During a constant pressure test, the wellbore storage coefficient dominates the initial response. The data will appear as a straight line with a unit slope on the log-log plot. This is normal. Do not mistake it for a flow regime. Then watch for the transition into the infinite acting radial flow period. This is where the curve bends away from the unit slope line and the derivative flattens out into a horizontal line. That horizontal derivative is your match point for estimating permeability. Read the match point values. Pick a point on the data curve and note its pressure and time coordinates, then pick the corresponding point on the type curve. Plug those values into the standard permeability equation for a constant pressure buildup interpretation, and you get kH directly. From there, skin follows from the vertical shift between your data curve and the type curve.

I ran into a real problem last year on a offshore gas well that had undergone a 14-day constant pressure test. The derivative on the Constant Pressure Analysis Chart showed what looked like a clean horizontal match point at around 80 hours. Permeability came out to roughly 12 millidarcies. But when I extended the analysis window and checked the normalized pressure, the derivative was not actually flat. It had a very slight upward trend that was easy to miss on a standard-resolution printout. The reservoir boundary was already influencing the response. My initial permeability estimate was about 15 percent too high because I matched at the wrong time window. The workaround was straightforward. I used a semi-log straight-line analysis on the same data and cross-checked the result. The semi-log yielded 10.4 millidarcies, which was the correct value. The boundary effect became obvious once I plotted the data on a Cartesian scale instead of relying solely on the log-log type curve match.

What the Charts Actually Tell You and What They Do Not

The main utility of a constant pressure analysis chart is identifying the flow regime and extracting permeability and skin from the match point. It works best for homogeneous, isotropic reservoirs with a single active boundary. The type curves assume infinite acting radial flow before any boundary effects appear, and that assumption breaks down the moment your test duration approaches the drainage radius divided by the diffusivity. A counter-intuitive point that beginners consistently miss: the downward slope of the derivative during the constant pressure phase does not indicate depletion. It indicates the transition from wellbore storage domination to formation flow control. Reading it as a depletion signature leads some engineers to falsely conclude the well is being starved. It is not. The well is flowing under a constant bottomhole pressure constraint, and the declining derivative is purely a mathematical consequence of the dimensionless formulation, not a reservoir performance indicator. Another pitfall is assuming the type curve match gives you absolute permeability without an independent estimate of viscosity or fluid properties. The match point requires known fluid properties. If you use an estimated viscosity from a stock tank sample that was taken weeks before the test, your permeability result will carry that error forward. Gas wells are especially sensitive to this. Viscosity changes significantly with pressure, and using a single average value across a large pressure drop can shift your permeability estimate by 20 to 30 percent. The fix is to use pressure-dependent viscosity correlations or run a compositional simulator to generate pseudo-properties for the test interval.

The charts also fail completely in fractured carbonate reservoirs where the dual-porosity response dominates. You will see two distinct dips in the derivative that the standard homogeneous type curve cannot fit. Forcing a match under those conditions produces garbage numbers. Use a Warren-Root or Kazaki-Matsumoto type curve instead. The constant pressure analysis chart is not the right tool for that geology, and pretending it works just to meet a deadline is how you end up with reservoir models that predict wrong decline curves for years. There is a practical limitation worth noting upfront. These charts require well-controlled constant pressure conditions, which means you need a functioning gas lift, a choked wellhead, or a sophisticated surface pressure control system. If your well is flowing against a fixed choke and the pressure drifts by more than 2 percent over the test duration, the dimensionless transformation becomes invalid and the type curve match loses meaning. I have seen technicians attempt a constant pressure interpretation on data where the flowing bottomhole pressure varied by nearly 8 percent over the stabilization period. The match looked fine visually but the permeability came out 40 percent higher than the semi-log result because the pressure variation contaminated the dimensionless conversion. The workaround in those cases is to fall back to a variable rate analysis method. Superposition time functions handle the pressure drift correctly. Agarwal's method or the normalized pressure approach from Lee's work will give you a reliable answer even when the constant pressure assumption is borderline. The extra plotting effort takes about 45 minutes versus 15 minutes for a straightforward type curve match, but it saves you from presenting incorrect formation parameters to the reservoir management team.

Getting the Chart and Using It in Practice

You do not need to purchase specialized software to use these charts. The type curves are available in the public domain from standard petroleum engineering references. The classic paper by Earlougher covers the fundamental dimensionless relationships. More recent publications from the Society of Petroleum Engineers provide updated type curves for fractured and heterogeneous systems. Many universities and engineering firms maintain digital versions of these charts in PDF or SVG format, and you can generate them yourself using spreadsheet software or Python with a few lines of code. If you want a ready-to-use version, check the SPE Technical Library or the API Technical Report series. Some commercial well test analysis packages also include these charts as built-in tools, though the built-in curves are often simplified compared to the full type curve sets found in the literature. The free alternatives are usually more complete and equally accurate if you know how to use them. The charts are straightforward once you stop treating them as magic matching exercises. Plot your data in dimensionless form. Identify the flow regimes by the shape of the derivative, not the pressure curve. Match the infinite acting radial flow period, not the wellbore storage portion. Cross-check your result with a semi-log analysis whenever the test duration is long enough to support it. And if your reservoir does not fit the homogeneous assumption, move to a dual-porosity chart immediately rather than forcing a match that looks convincing but is technically wrong.