Final Shut-In Period

Key Takeaways

• The Horner time ratio calculation for the final shut-in period uses the equivalent producing time (tp) — defined as the ratio of cumulative production to the final flow rate — rather than the actual clock time of the last production period, because the superposition principle requires that all previous production history be accounted for; when the production history before the final shut-in is complex (multiple rate changes, shut-ins, stimulation treatments), the equivalent producing time calculated from cumulative production divided by the last rate is the approximation that collapses all of that history into a single effective producing time for the Horner plot; this approximation is accurate when the final production period is long relative to all previous production periods (so that the pressure transient has forgotten the earlier rate changes), but introduces error when the final rate period is short and the pressure has not reached radial flow equilibrium with the preceding multi-rate history; modern pressure transient analysis software avoids this approximation by using numerical superposition across the entire rate history, which correctly accounts for the pressure history without requiring the tp approximation and produces more accurate permeability and skin estimates from the same shut-in data.
• Wellbore storage masking of the early buildup data in the final shut-in period is the primary reason that the full buildup period must be analyzed rather than just the earliest pressure readings — when the well is shut in at the surface (by closing the wellhead valve), the wellbore fluid column continues to expand into the formation (or the gas in the wellbore continues to compress and desaturate the fluid column) for a period determined by the wellbore storage coefficient; during this wellbore storage-dominated period, the surface shut-in pressure does not reflect the reservoir pressure response at the perforations but rather the decompression of the wellbore fluid system; the wellbore storage period on a log-log plot of the pressure derivative appears as a unit-slope line (pressure change proportional to time), and the radial flow period that provides the Horner straight line begins only after the derivative departs from unit slope by 1.5 log cycles or more; the duration of wellbore storage depends on the wellbore storage coefficient (determined by the wellbore volume and fluid compressibility) and the formation permeability (lower permeability extends the wellbore storage period because the formation cannot accept fluid fast enough to transition to matrix-controlled flow); for low-permeability wells, wellbore storage can mask radial flow for hours or days, requiring correspondingly long final shut-in periods to capture the straight-line data that formation evaluation requires.
• The final shut-in period duration target is determined by calculating the time required to exit wellbore storage effects and enter the radial flow regime, which is estimated from the wellbore storage coefficient and the formation permeability derived from the first-pass analysis of the available data — a practical rule for estimating the required shut-in duration is that the shut-in should extend at least 1.5 log cycles in time beyond the estimated end of wellbore storage (approximately when the log-log pressure derivative shows a flat plateau beginning), which often means the total shut-in should be 5-10 times the duration of the wellbore storage period; the minimum required shut-in time for a useful Horner analysis can range from a few hours for a high-permeability reservoir (100+ millidarcy) to several weeks for a tight formation (0.1 millidarcy or less) where wellbore storage is prolonged by the slow pressure equilibration between the wellbore and the formation; planning the final shut-in period duration before the test begins (using preliminary estimates of formation permeability from nearby analogues and the wellbore storage coefficient from the planned tubing size and fluid density) avoids the costly situation where the shut-in is terminated before adequate straight-line data are obtained and the test must be rerun.
• Reservoir boundary effects that appear in the final shut-in period data provide additional information about the drainage area and structural setting of the reservoir beyond the permeability and skin information extracted from the radial flow period — after the pressure transient reaches a sealing fault or the edge of a closed reservoir compartment during the shut-in, the pressure derivative departs from the flat radial flow plateau upward (indicating that the depletion from the bounded reservoir is steepening the buildup curve), providing an estimate of the distance to the boundary from the time at which the departure occurs; if the final shut-in is long enough and the reservoir is small enough (or faulted), the pressure may approach pseudo-steady-state depletion behavior even during the shut-in, allowing the average reservoir pressure within the drainage area to be estimated from the extrapolated Horner straight line (the p* value) or from the modified Dietz method for bounded reservoirs; the decision to extend the final shut-in until boundary effects appear is an economic balance between the rig time cost of a longer shut-in and the additional reservoir characterization value of the boundary distance estimate, which informs future well placement and reserve estimation for the drainage compartment.
• Distorted final shut-in periods are a common quality control concern in well test analysis and result from several operational situations that violate the assumption of a clean rate history preceding the buildup — when the well is shut in for a wellbore cleanup or wellbore storage period and then re-opened briefly to unstick the rods or flush the pump before the final shut-in, the brief re-opening distorts the pressure history that the Horner analysis assumes was a clean final rate period; when the production rate changes significantly in the hours before shut-in (due to choke adjustments, pump speed changes, or separator liquid level fluctuations), the variable rate history invalidates the single-rate Horner analysis and requires multi-rate superposition; when the well continues to produce into the casing annulus after the tubing has been shut in (through a leaking packer or incomplete annulus shut-in), the afterflow into the formation continues after the surface shut-in and the wellbore storage coefficient is effectively increased above its tubing-only value; these distortions are identified by comparing the actual derivative response with the theoretical wellbore storage signature and flagging anomalous behavior for investigation before interpreting the pressure data as a clean buildup signal.