5.3 Shut-In Drill Pipe Pressure (SIDPP), Shut-In Casing Pressure (SICP) & Pit Gain

Following well shut-in, the rig crew transitions from emergency response to pressure analysis and kill sheet preparation. The surface pressures recorded on the drill pipe and casing gauges provide a clear diagnostic window into downhole conditions.

Interpreting Shut-In Drill Pipe Pressure ($SIDPP$), Shut-In Casing Pressure ($SICP$), and active pit volume gain enables the crew to determine formation pore pressure, evaluate casing shoe integrity, identify influx density, and calculate the required Kill Mud Weight ($KMW$).

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Pressure Stabilization Dynamics

Surface pressure gauges do not reflect true reservoir conditions immediately after BOP closure. Pressures require 5 to 15 minutes to stabilize.

Stabilization Factors

1. Dynamic Wave Dissipation: Shutting down mud pumps and closing preventers creates transient pressure reverberations that dissipate over several minutes.
2. Formation Pressure Buildup: In low-permeability reservoirs (tight sands or shales), formation fluid enters the wellbore slowly. The pressure differential across the borehole wall requires time to reach static equilibrium with formation pore pressure.
3. Thermal Equalization: Temperature differentials between the drill string, annulus, and formation gradually normalize after circulation ceases.

Stabilization vs. Active Gas Migration

After shut-in the well is monitored continuously: check that there is no flow at the flowline or past the closed BOP, and record well pressures at regular intervals. Rig crews record pressures at 1-minute intervals to observe the pressure curve:

• True Stabilization: Pressures rise with a decreasing slope and flatten into a horizontal, steady plateau. These stabilized values represent official $SIDPP$ and $SICP$.
• Gas Migration: If pressures flatten briefly and then resume a continuous, linear climb (e.g., 50–100 psi every 10 minutes on both gauges simultaneously), an unexpanded gas bubble is migrating up the wellbore, requiring volumetric pressure control.

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The Wellbore U-Tube Model & Formation Pressure ($SIDPP$)

The wellbore functions as a giant hydraulic U-tube, where the drill string forms one leg, the annulus forms the second leg, and the open hole at the bit forms the balance point exposed to formation pore pressure ($FP$).

Why SIDPP Reflects True Formation Pore Pressure

Without a float valve, the drill string leg contains an uncontaminated column of original drilling mud of known, uniform density throughout its entire true vertical depth ($TVD$):

$HP_{\text{drillstring}} = 0.052 \times MW \times TVD$

Because no formation fluid entered the drill pipe bore, its hydrostatic pressure is calculated with absolute precision. At the bottom of the wellbore, drill string hydrostatic pressure plus surface drill pipe backpressure balances formation pore pressure:

$FP = HP_{\text{drillstring}} + SIDPP = (0.052 \times MW \times TVD) + SIDPP$

Therefore, $SIDPP$ represents the exact underbalance deficit between the original mud column and the formation pore pressure. This makes $SIDPP$ the mandatory baseline for calculating Kill Mud Weight (KMW):

$KMW = MW + \frac{SIDPP}{0.052 \times TVD}$

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Why SICP is Typically Higher Than SIDPP

In virtually every well control event, the stabilized Shut-In Casing Pressure ($SICP$) is significantly higher than the Shut-In Drill Pipe Pressure ($SIDPP$):

$SICP > SIDPP$

The Hydrostatic Deficit Mechanism

Both legs of the U-tube communicate at the well bottom and must balance the identical formation pore pressure ($FP$):

$FP = HP_{\text{drillstring}} + SIDPP = HP_{\text{annulus}} + SICP$

Rearranging to compare surface pressures:

$SICP - SIDPP = HP_{\text{drillstring}} - HP_{\text{annulus}}$

Because the influx entered the wellbore through the open hole, it resides in the annulus. Reservoir fluids—methane gas ($0.1 - 0.3 \text{ psi/ft}$), crude oil ($0.3 - 0.4 \text{ psi/ft}$), and saltwater ($0.43 - 0.50 \text{ psi/ft}$)—all possess lower densities than the drilling mud ($0.50 - 0.85+ \text{ psi/ft}$) they displace.

Because the annular leg contains lighter fluid, its total hydrostatic head ($HP_{\text{annulus}}$) is lower than the drill string hydrostatic head ($HP_{\text{drillstring}}$). To maintain equilibrium with formation pressure, the casing gauge at surface must hold additional backpressure exactly equal to the missing annular hydrostatic head:

$SICP - SIDPP = (G_{\text{mud}} - G_{\text{influx}}) \times L_{\text{influx}}$

Where $G_{\text{mud}}$ is mud gradient (psi/ft), $G_{\text{influx}}$ is influx gradient (psi/ft), and $L_{\text{influx}}$ is vertical influx height (ft).

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Float Valves in the Drill String & Float Bumping Procedures

Drilling assemblies often include a drill pipe float valve (flapper or plunger non-return valve) above the bit to prevent cuttings backflow.

The Float Valve Challenge

Upon shut-in, the float valve closes under reverse differential pressure, isolating the drill string bore from formation pressure. The standpipe gauge reads 0 psi, while the casing gauge registers positive $SICP$. True $SIDPP$ cannot be read directly.

Standard Float Bumping Procedure

To establish true $SIDPP$ without overpressuring the well:

1. Confirm that $SICP$ is fully stabilized.
2. Line up a high-pressure pump (cementing unit or mud pump) to the drill string.
3. Pump drilling mud into the drill pipe at an ultra-slow rate (0.1 to 0.2 bbl/min or slow manual pump strokes).
4. Observe the drill pipe gauge as pressure climbs linearly.
5. The Hesitation Point: The instant pump pressure inside the string slightly exceeds wellbore pressure below the valve, the flapper cracks open. The drill pipe pressure needle will hesitate, dip, or slow its climb, and the casing gauge will register its first micro-pulse.
6. Stop Pumping as Soon as Casing Pressure Starts to Rise: Read the drill pipe pressure at that point. If the casing pressure has risen above the original SICP, that rise is overpressure trapped by pumping, so subtract it: $SIDPP = \text{drill pipe reading} - \text{rise in casing pressure}$.

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Dedicated Gauges for SIDPP and SICP

Shut-in pressures are read on specific, dedicated gauges:

• SIDPP: the drill pipe (standpipe) pressure gauge, normally read at the remote choke panel, with the drill-floor standpipe gauge as a cross-check.
• SICP: the casing (choke manifold) pressure gauge upstream of the chokes, also displayed at the remote choke panel.

Use the same gauges for the whole operation, record which gauges were used, and choose gauges whose range suits the expected pressures, because low shut-in pressures are hard to read accurately on a high-range gauge. Gauges that disagree must be reported and checked, since every kill-sheet calculation depends on these readings.

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Determining Influx Height, Gradient & Fluid Type

By combining surface shut-in data with wellbore geometry, the drilling team can identify the influx fluid type.

Step 1: Calculate Influx Height ($L_{\text{influx}}$)

The influx volume equals the pit volume gain recorded at shut-in. For an influx positioned around the drill collars:

$L_{\text{influx}} = \frac{\text{Pit Gain (bbl)}}{C_{\text{annular}} (\text{bbl/ft})}$

Where $C_{\text{annular}} = \frac{ID_{\text{hole}}^2 - OD_{\text{collar}}^2}{1029.4}$.

Step 2: Calculate Influx Gradient ($G_{\text{influx}}$)

Using the annular hydrostatic deficit relationship:

$G_{\text{influx}} = G_{\text{mud}} - \frac{SICP - SIDPP}{L_{\text{influx}}}$

Where $G_{\text{mud}} = 0.052 \times MW$.

Step 3: Diagnostic Identification of Influx Fluid

• $G_{\text{influx}} < 0.20 \text{ psi/ft}$: Gas influx (methane). Expect high surface pressures and rapid gas expansion during circulation.
• $0.20 \le G_{\text{influx}} < 0.40 \text{ psi/ft}$: Crude oil or condensate.
• $G_{\text{influx}} \ge 0.40 \text{ psi/ft}$: Formation saltwater.

Worked Engineering Example

• Well Depth: $TVD = 10{,}000 \text{ ft}$
• Mud Weight: $MW = 11.5 \text{ ppg}$ ($G_{\text{mud}} = 0.052 \times 11.5 = 0.598 \text{ psi/ft}$)
• Collar Annular Capacity: $C_{\text{ann}} = 0.02914 \text{ bbl/ft}$
• Stabilized Pressures: $SIDPP = 450 \text{ psi}$, $SICP = 750 \text{ psi}$, Pit Gain = $20 \text{ bbl}$

Calculations:

1. Influx Height: $L_{\text{influx}} = \frac{20 \text{ bbl}}{0.02914 \text{ bbl/ft}} = 686.3 \text{ ft}$
2. Pressure Differential: $SICP - SIDPP = 750 - 450 = 300 \text{ psi}$
3. Influx Gradient: $G_{\text{influx}} = 0.598 - \frac{300}{686.3} = 0.598 - 0.437 = 0.161 \text{ psi/ft}$
4. Formation Pore Pressure: $FP = (0.052 \times 11.5 \times 10{,}000) + 450 = 5{,}980 + 450 = 6{,}430 \text{ psi}$
5. Diagnostic Conclusion: Gradient of $0.161 \text{ psi/ft}$ confirms a methane gas kick.