6.1 Kill Sheet Fundamentals & Pre-Recorded Data

During a well control emergency, high stress, time constraints, and complex downhole dynamics make manual, ad-hoc calculations hazardous. The standard IWCF kill sheet is a systematic, pre-engineered calculation template designed to organize well geometry, tubular capacities, pump outputs, and hydraulic pressure baselines before a kick occurs. By pre-recording well data during routine operations, the rig team ensures that once a kick is detected and the well is secured, only three live variables—Shut-In Drill Pipe Pressure (SIDPP), Shut-In Casing Pressure (SICP), and Pit Gain—are needed to immediately establish the complete kill plan.

---

Purpose and Architecture of the IWCF Kill Sheet

The kill sheet fulfills three critical operational functions:

1. Continuous Baseline Monitoring: Tracks wellbore volume changes, circulation times, and formation fracture limits as drilling deepens.
2. Rapid Post-Kick Parameter Determination: Converts raw shut-in pressures into Kill Mud Weight (KMW), Initial Circulating Pressure (ICP), Final Circulating Pressure (FCP), and revised Maximum Allowable Annular Surface Pressure (MAASP).
3. Operational Roadmap for Choke Manipulation: Establishes the stroke-by-stroke drill pipe pressure step-down table that the choke operator follows to maintain constant bottom-hole pressure.

Functional Sections of the Kill Sheet

• Well Geometry & Depths: Hole diameter, casing outer/inner diameter, casing shoe Measured Depth (MD) and True Vertical Depth (TVD), total well MD and TVD, and current drilling fluid density.
• Drill String Internal Capacity: Dimensions, unit capacities, lengths, and calculated internal volumes for drill pipe (DP), heavy-weight drill pipe (HWDP), and drill collars (DC).
• Annular Capacity: Capacities and volumes for casing-by-drill pipe, open hole-by-drill pipe, open hole-by-HWDP, and open hole-by-drill collars, plus surface choke line volumes.
• Mud Pump Displacement Data: Triplex pump liner size, stroke length, volumetric efficiency, and displacement output per stroke ($V_{\text{stk}}$) for each active pump.
• Pre-Recorded Hydraulics: Slow Circulation Rate (SCR) pressures measured across multiple pump speeds (e.g., 20, 30, and 40 SPM) through both the normal flowline and the choke line.
• Formation Fracture Data: Leak-Off Test (LOT) pressure, Equivalent Mud Weight (EMW), and initial MAASP.

---

Drill String Internal Capacity & Volume Calculations

The drill string serves as a clean, uncontaminated fluid conduit from surface to the bit nozzles. Because wall thickness and internal diameters vary across tubular components, the internal volume is calculated segment by segment.

Capacity Formulas

In oilfield imperial units, internal capacity ($C_{\text{id}}$) in barrels per linear foot ($\text{bbl/ft}$) is calculated from the pipe inner diameter ($ID$, in inches):

$C_{\text{id}} = \frac{ID^2}{1029.4}\quad [\text{bbl/ft}]$

In metric units, internal capacity in liters per linear meter ($\text{l/m}$) is:

$C_{\text{id}} = \frac{ID^2}{1273.2}\quad [\text{l/m}]$

Where $ID$ is in millimeters.

Segment Volume Determination

The fluid volume of each tubular component is the product of its length ($L$) and unit capacity ($C_{\text{id}}$):

$V_{\text{section}} = L \times C_{\text{id}}$

Total drill string volume ($V_{\text{string}}$) is the cumulative sum of all internal tubular volumes:

$V_{\text{string}} = V_{\text{DP}} + V_{\text{HWDP}} + V_{\text{DC}}$

---

Annular Capacity Sections & Wellbore Volumes

The annular space is the void between the outer diameter of the drill string ($D_1$) and the inner diameter of the casing or open hole ($D_2$).

Annular Capacity Formulas

In imperial units:

$C_{\text{ann}} = \frac{D_2^2 - D_1^2}{1029.4}\quad [\text{bbl/ft}]$

In metric units:

$C_{\text{ann}} = \frac{D_2^2 - D_1^2}{1273.2}\quad [\text{l/m}]$

Annular Segmentation

The annular volume is divided into distinct sections reflecting changing hole and tubular diameters:

1. Casing Annulus ($V_{\text{csg-DP}}$): Volume between casing ID and drill pipe OD from surface to casing shoe depth.
2. Open Hole vs. Drill Pipe ($V_{\text{OH-DP}}$): Volume between drilled hole diameter and drill pipe OD from casing shoe to top of HWDP.
3. Open Hole vs. HWDP ($V_{\text{OH-HWDP}}$): Volume between drilled hole diameter and HWDP OD.
4. Open Hole vs. Drill Collars ($V_{\text{OH-DC}}$): Volume between drilled hole diameter and collar OD. Because drill collars have large outer diameters, this section exhibits the lowest unit capacity and smallest clearance, resulting in the highest annular fluid velocities.
5. Surface Choke Line Volume ($V_{\text{choke}}$): Fluid volume of high-pressure lines connecting the BOP stack to the choke manifold. On subsea rigs, long choke and kill lines (extending through thousands of feet of water) contain substantial volumes that must be accounted for.

Worked Example: Annular Volume, Strokes and Time

Open hole of 8-1/2 in around 5 in drill pipe, 1,000 ft long; the pump delivers 0.100 bbl/stroke at 30 SPM.

1. Annular capacity: $\frac{8.5^2 - 5.0^2}{1029.4} = \frac{72.25 - 25.00}{1029.4} = 0.0459\text{ bbl/ft}$
2. Volume: $1{,}000 \times 0.0459 = 45.9\text{ bbl}$
3. Strokes: $45.9 \div 0.100 = 459\text{ strokes}$
4. Time at 30 SPM: $459 \div 30 = 15.3\text{ minutes}$

Pump output per minute is the displacement per stroke multiplied by the pump rate ($0.100 \times 30 = 3.0\text{ bbl/min}$), so the same result is $45.9 \div 3.0 = 15.3$ minutes.

Total Annular & Open Hole Volumes

• Total Open Hole Annular Volume ($V_{\text{OH}}$): The fluid volume in the open hole below the casing shoe: $V_{\text{OH}} = V_{\text{OH-DC}} + V_{\text{OH-HWDP}} + V_{\text{OH-DP(open)}}$
• Total Annular Volume ($V_{\text{annulus}}$): The cumulative annular volume from the bit to the surface wellhead: $V_{\text{annulus}} = V_{\text{csg-DP}} + V_{\text{OH}} + V_{\text{choke}}$
• Total Well System Volume: The complete fluid contents of the wellbore: $V_{\text{system}} = V_{\text{string}} + V_{\text{annulus}}$

---

Pump Displacement and Stroke Calculations

Triplex mud pumps deliver a fixed volume of fluid per mechanical stroke. Pump displacement output ($V_{\text{stk}}$) depends on liner diameter ($D_{\text{liner}}$), stroke length ($L_{\text{stroke}}$), and volumetric efficiency ($\eta_{\text{vol}}$, typically 95%–98%):

$V_{\text{stk}} = 0.000243 \times D_{\text{liner}}^2 \times L_{\text{stroke}} \times \eta_{\text{vol}}\quad [\text{bbl/stk}]$

Converting barrel capacities into pump stroke counts establishes the operational timing for kill operations:

• Strokes to Bit (Surface to Bit): Number of pump strokes required to pump fluid from surface mud pumps through the drill string to the bit nozzles: $\text{Strokes to Bit} = \frac{V_{\text{string}}}{V_{\text{stk}}}$
• Strokes Bit to Shoe: Number of strokes required to circulate fluid from the bit up to the casing shoe: $\text{Strokes Bit to Shoe} = \frac{V_{\text{OH}}}{V_{\text{stk}}}$
• Strokes Bit to Surface (Total Annular Strokes): Strokes required to circulate fluid from the bit to the surface flowline: $\text{Strokes Bit to Surface} = \frac{V_{\text{annulus}}}{V_{\text{stk}}}$
• Total Well System Circulation Strokes: $\text{Total Strokes} = \text{Strokes to Bit} + \text{Strokes Bit to Surface}$
• Circulation Time: Operating time required to complete each circulation phase at a designated kill speed: $\text{Time (minutes)} = \frac{\text{Stroke Count}}{\text{Kill Rate (SPM)}}$

---

Pre-Recorded Hydraulics: Slow Circulation Rate (SCR) Table

A Slow Circulation Rate (SCR)—also termed Reduced Circulating Pressure (RCP)—is the circulating pressure required to pump mud through the well system at a reduced rate (typically 20 to 40 SPM, or roughly one-third to one-half of normal drilling rate). Reduced pump rates limit friction backpressure on exposed open hole formations, reduce choke erosion, and afford the choke operator sufficient reaction time.

Operational Rules for SCR Recording

Typical rig procedures require SCR pressures to be taken and logged on the kill sheet:

• At the beginning of each 12-hour tour (shift).
• After any change in mud density, viscosity, or solids content.
• Following bit, nozzle, or downhole tool (motor/MWD) replacements.
• After drilling significant new footage (e.g., every $500\text{ ft}$ / $150\text{ m}$).
• On each active and standby mud pump.
• Through both the normal riser/bell nipple and through the dedicated choke line.

The table is an example only; real values are measured on the rig.

---

Pre-Recorded Casing Shoe Fracture Data & Initial MAASP

The formation immediately below the casing shoe is normally assumed to be the weakest exposed point in the open hole. After cementing casing and drilling out the shoe track, a Leak-Off Test (LOT) determines the formation fracture breakdown gradient, expressed as an Equivalent Mud Weight (LOT EMW):

$\text{LOT EMW} = \text{Test MW} + \frac{\text{Surface Leak-off Pressure}}{0.052 \times \text{Casing Shoe TVD}}$

From this baseline, the initial Maximum Allowable Annular Surface Pressure (MAASP) is calculated:

$\text{MAASP} = (\text{LOT EMW} - \text{Current MW}) \times 0.052 \times \text{Casing Shoe TVD}$