6.1 Shut-In Pressures (SIDPP, SICP) & Influx Height / Gradient

Following an emergency shut-in on a kick, wellsite supervisors must rapidly and accurately interpret surface pressure gauges. Shut-in drillpipe pressure ($\text{SIDPP}$) and shut-in casing pressure ($\text{SICP}$) provide the fundamental empirical data required to calculate formation pore pressure, evaluate downhole influx geometry, determine fluid density, and prepare the formal IWCF kill sheet.

The Wellbore U-Tube in Static Shut-In Conditions

For the standard calculation, assume a static well on bottom, a clean communicating drillstring, a discrete annular influx and no trapped or migration overpressure, losses or crossflow. Compare gauges at a common datum. The well then acts as a U-tube manometer. The two vertical columns—the drillstring interior (Leg 1) and the annular space (Leg 2)—meet at the drill bit nozzles on bottom:

• Drillstring Leg: Under normal drilling conditions prior to a kick, the interior of the drillpipe, heavyweight drillpipe, and drill collars contains uncontaminated drilling fluid of known, uniform density (Original Mud Weight, $\text{OMW}$).
• Annular Leg: The open hole and casing annulus contains drilling fluid contaminated by the formation kick, which forms an influx column at or near bottomhole.
• Bottomhole Equalization Datum: In accordance with Pascal's law of fluid statics, the total pressure at the bottom of both legs must balance formation pore pressure ($P_{\text{form}}$) once the well is shut in and pressures stabilize:

$P_{\text{form}} = P_{\text{hyd, dp}} + \text{SIDPP} = P_{\text{hyd, ann}} + \text{SICP}$

Where:

• $P_{\text{hyd, dp}}$ = Hydrostatic pressure of the fluid column inside the drillstring ($\text{psi}$)
• $\text{SIDPP}$ = Shut-In Drillpipe Pressure recorded at the standpipe gauge ($\text{psi}$)
• $P_{\text{hyd, ann}}$ = Combined hydrostatic pressure of the mud and influx in the annulus ($\text{psi}$)
• $\text{SICP}$ = Shut-In Casing Pressure recorded at the choke manifold gauge ($\text{psi}$)

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Drillpipe Pressure as a Clean Fluid Manometer

In this model, the formation fluid enters the annulus and the drillstring retains homogeneous original mud. Its known hydrostatic head plus communicating SIDPP gives the formation-pressure estimate. A slug, contaminated string, off-bottom bit or isolated gauge requires its own pressure profile.

To calculate static formation pore pressure ($P_{\text{form}}$):

$P_{\text{form}} = (0.052 \times \text{OMW} \times \text{TVD}) + \text{SIDPP}$

Where:

• $\text{OMW}$ = Original mud weight in pounds per gallon ($\text{ppg}$)
• $\text{TVD}$ = True vertical depth of the wellbore in feet ($\text{ft}$)
• $0.052$ = Oilfield volumetric-to-areal pressure conversion constant ($\text{psi} / (\text{ppg} \times \text{ft})$)

Obtaining SIDPP with a Drillpipe Float

An unported float prevents reverse flow and may isolate the standpipe gauge. Its reading can be zero or a trapped, unreliable pressure; it must not be entered as true SIDPP without checking communication.

One approved approach uses a recent accurate SCR measurement for the same pump, flow rate, fluid and string configuration:

1. Confirm the float-measurement procedure and record stabilized casing pressure. Align the equipment and communicating gauges as specified for that rig.
2. Open the float by cautiously starting circulation, coordinating the choke to preserve bottomhole pressure. For a surface stack with negligible annular friction, hold the initial casing-pressure reference; for a subsea choke return, account for developing CLF.
3. Stabilize at the selected recorded low flow rate. Estimate SIDPP as circulating standpipe pressure minus the corresponding original-mud SCR pressure.
4. Shut down in a controlled manner while preserving bottomhole pressure, and record the result and method. The standpipe reading may again become isolated when the float closes.

If the SCR data are unsuitable, use the approved slow bump/breakback or other float-measurement procedure. Do not infer flow rate from spm alone or alter dampener valves from a generic recipe.

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Interpreting Shut-In Casing Pressure (SICP) Versus SIDPP

With original mud in a communicating drillstring and a lighter influx confined to the annulus, the expected static relationship is:

$\text{SICP} > \text{SIDPP}$

The Annular Hydrostatic Deficit

A gas, oil or water influx that is lighter than the original mud reduces annular hydrostatic head. When an influx occupies a vertical height ($h$) in the annulus, it displaces an equivalent height of heavy drilling mud. This creates an annular hydrostatic deficit:

$P_{\text{hyd, ann}} < P_{\text{hyd, dp}}$

Because the total bottomhole pressure must satisfy U-tube equilibrium ($P_{\text{hyd, dp}} + \text{SIDPP} = P_{\text{hyd, ann}} + \text{SICP}$), the surface casing gauge must exert additional backpressure to counterbalance the lighter annular column:

$\text{SICP} - \text{SIDPP} = P_{\text{hyd, dp}} - P_{\text{hyd, ann}}$ $\text{SICP} - \text{SIDPP} = h \times (G_{\text{mud}} - G_{\text{inf}})$

Where:

• $h$ = Vertical height of the influx column ($\text{ft}$)
• $G_{\text{mud}}$ = Hydrostatic pressure gradient of the original mud ($0.052 \times \text{OMW}$, $\text{psi/ft}$)
• $G_{\text{inf}}$ = Hydrostatic pressure gradient of the formation influx ($\text{psi/ft}$)

Diagnostic Interpretations of Gauge Discrepancies

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Calculating Influx Height Across Complex Annular Geometries

In the standard discrete-influx volume model, the net pit gain at shut-in is taken as the downhole influx volume ($V_{\text{inf}}$ in barrels). To calculate influx height ($h$), supervisors must map this volume against the cross-sectional annular capacity factors of the bottomhole assembly.

Annular capacity ($C_{\text{ann}}$) is defined as:

$C_{\text{ann}} = \frac{D_{\text{hole}}^2 - D_{\text{pipe, OD}}^2}{1029.4} \quad (\text{bbl/ft})$

Case 1: Influx Confined Entirely Around Drill Collars

If the pit gain ($V_{\text{inf}}$) is less than or equal to the annular volume surrounding the drill collars ($V_{\text{ann, dc}} = L_{\text{dc}} \times C_{\text{ann, dc}}$):

$h = \frac{V_{\text{inf}}}{C_{\text{ann, dc}}}$

Case 2: Influx Spanning Drill Collars and Drillpipe

Because drill collars have a larger outer diameter than drillpipe, the collar-hole annular clearance is narrow ($C_{\text{ann, dc}} < C_{\text{ann, dp}}$). If the pit gain exceeds the collar annular volume, the influx overflows into the larger drillpipe annulus:

1. Calculate volume around drill collars: $V_{\text{ann, dc}} = L_{\text{dc}} \times C_{\text{ann, dc}}$
2. Calculate remaining influx volume in drillpipe annulus: $V_{\text{rem}} = V_{\text{inf}} - V_{\text{ann, dc}}$
3. Calculate influx height in drillpipe annulus: $h_{\text{dp}} = \frac{V_{\text{rem}}}{C_{\text{ann, dp}}}$
4. Calculate total vertical influx height: $h = L_{\text{dc}} + h_{\text{dp}}$

(Note: In directional wells, measured lengths must be converted to true vertical heights using wellbore survey inclination data.)

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Influx Density and Pressure Gradient Determination

Once total influx height ($h$) and the differential pressure ($\text{SICP} - \text{SIDPP}$) are known, the average hydrostatic gradient of the kicking fluid is calculated directly:

$G_{\text{inf}} = G_{\text{mud}} - \frac{\text{SICP} - \text{SIDPP}}{h}$

In terms of equivalent mud density ($\rho_{\text{inf}}$ in $\text{ppg}$):

$\rho_{\text{inf}} = \text{OMW} - \frac{\text{SICP} - \text{SIDPP}}{0.052 \times h}$

Influx Identification Matrix

Evaluating calculated influx gradients enables drilling supervisors to predict downhole expansion hazards and surface pressure loads: