Excessive Swabbing

As noted earlier, swabbing is the reduction of bottom hole pressure caused by upward pipe movement. As the pipe is being pulled out during trips, mud flows down through the annulus to replace the volume of drilling tools removed from the hole. There is, thus, viscous drag between upward-moving drill stem and the mud, and between the downward mud flow and the casing/hole. This causes a frictional pressure loss in the direction of the surface. The result is reduced bottom hole pressure. The higher the trip speed, the worse this effect. The swab pressure depends on:

• Pipe velocity.
• Bit and/or BHA ‘balling’
• Clearance between pipe and hole - the smaller the annular cross section, the greater the swabbing action.
• Mud rheology - the higher the viscosity, the greater the swabbing action.

Excessive Drilling Rate in Gas-Bearing Formations

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The densities of formation fluids (gas, oil or water) are much lower than that of conventional drilling fluids. Any influx of formation fluid therefore reduces the mud density in the annulus. This influx, otherwise known as mud cut, is measured using sensors that measure mud density and conductivity at injection and at flow line.

Mud cut may occur from:

• Influx due to inadequate mud weight or swabbing
• Diffusion of fluid into the hole due to the pressure in the annulus being lower than the pore pressure
• Air entrained in mud during trips (the so-called ‘kelly air’)
• Expansion of drilled gas as it reaches the surface.

The majority of such kick problems arise from the reduction of mud weight due to the expansion of drilled gas, especially in large diameter holes, such as surface holes drilled at high rates. For such holes drilled without a blowout preventer in place, a small reduction in mud weight can lead to a violent kick and with the loss of primary control, lead to a blowout.

Kick Detection

A kick can occur at any time while drilling a well. To prevent any major catastrophe, early kick detection is essential for proper well control. As a primary precaution, it is important for all personnel, including the mud logger, to be in a state of readiness. Certain pre-kick information must be collected and available for use in case a kick occurs. These include volumes and pressures data. A Kick

Pre-kick data requirements are as follows:

Maximum Working Casing Pressure

The casing and blowout preventer (BOP) are designed for the different expected pressures during each drilling phase. This is determined during well planning and is generally the maximum pressure rating of the BOP and its outlets or 80% of the burst pressure of the last casing. The 80% consideration is a safety factor for the casing string.

Maximum Allowable Annulus Surface Pressure (MAASP)

This is the annulus pressure at the surface that corresponds to the pressure at the weakest point of the hole. Fracture gradient at the last casing shoe usually defines the weakest point. However; for some boreholes, the MAASP can be the casing burst pressure or BOP rupture pressure if they are less than the fracture gradient (this is poor well design) or a permeable or weaker formation in the open hole. The MAASP represents the maximum annulus pressure that can be tolerated without risking losses while controlling a kick. The MAASP is estimated from the following equation:

Rig Capacity for Weighting Mud

Although this data does not appear in the well-kill worksheet, it is important, as it defines the number of circulation cycles necessary to regain primary control with the given change of mud. The rig capacity depends on total reserves of weighting materials (Barites, etc) and the maximum rate of addition to system. The maximum rate of addition is measured in lb/min or kg/min. Backup supply MUST always be available on the rig.

System Pressure Losses (SPL) at Slow Pump Rate SPR (or Slow Circulation Rate - SCR)

Circulation at the normal pump rate for drilling may produce surface pressures greater than the MAASP. We use a slow pump rate to kill the well partly for this reason, but also because it gives us more time to think, to observe what is happening and to DO THE JOB CAREFULLY. Therefore a System Pressure Loss at Slow Pump Rate (SPR, or SCR – Slow Circulation Rate) for kick control must be determined at regular intervals. This is usually 20 or 30 strokes per minute for a large triplex pump.

This slow rate must be taken:

• At the start of each tour
• If the mud weight changes
• If bit configuration changes (e.g. a nozzle becomes plugged)
• After bit and/or BHA changes.

If a kick occurs, the influx will be circulated out at the predetermined slow circulation rate. This is called the kill rate. The pressure losses must always include the choke line pressure losses, especially offshore, with a subsea BOP, where this could be substantial.

Pump, String, and Hole Configuration.

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This includes the data used for the determination of the lag time (surface to bit and bit to surface) and contains:

• Pump capacity
• Hole size
• Drill string capacity (internal volume)
• BHA capacity
• Annular capacity (bit to casing shoe and casing shoe to BOP)
• Casing data (size, weight, burst pressure, shoe depth)
• The worksheet includes the space to fill in lag time in strokes or minutes for the proposed kill rate.

This estimation is usually computerised and continuously logged. IT IS IMPORTANT THAT YOU KNOW HOW TO CALCULATE THESE THINGS WITHOUT A COMPUTER.

Kick Detection Techniques.

There are a number of indicators that provide early warning of kick occurrence. Positive kick indicators are:

• Mud pit level/flow increase
• Incorrect hole fill up during trip
• Decrease in standpipe pressure/increase in pump rate
• Increase/decrease in drill stem weight.

Potential indicators are:

• Increase in penetration rate;
• Lost circulation;
• Changes in gas levels, mud density and mud conductivity.

Parameters used for detecting abnormal pressure zones are also potential kick indicators. These include:

• Torque, overpull and drag;
• Shale caving increase;
• Shale density/shale factor changes;
• Flowline mud temperature changes;
• ‘d’ Exponent changes.

The surest indicators of a kick occurring are Mud Pit Level Increase and Flow Increase together.

Incorrect Fill-up During Trips

When pulling out of the hole, if the volume of mud pumped to keep the hole full is less than that normally required, then there is an evidence of influx. The mud volume required should be equal to or slightly greater than the displacement of the drill pipe (normally five stands) pulled. Mud loggers and drilling engineers MUST follow trips even though an automatic trip monitor is usually used.

Conversely during a trip into the hole, the downward movement of the drill pipe expels fluid from the annulus to the trip tank or active mud system. This return flow should cease a few seconds after pipe movement stops. If flow continues, then there is may be a kick.

Decrease in Standpipe Pressure/Increase in Pump Rate

As indicated in the U-tube analogy, influx of fluid into the annulus creates an imbalance resulting in a decrease in hydrostatic pressure in the annulus. In such an unbalanced system, gravity helps move drilling fluid down the hole, requiring less energy from the pump. This will result in a decrease in the standpipe pressure.

This is not the only reason that there may be an increase in pump rate and decrease in standpipe pressure: a wash-out in the drill stem can also cause these indicators. It is important to pick up and check for flow. If there is no flow but the rate of change of pressure is showing an increasing trend, it is probably a wash-out. Either way, it cannot be ignored – action must be taken.

Increase/Decrease in Drill Stem Weight

Any influx into the wellbore from the formation reduces the density of the annular drilling fluid. This reduces the buoyant force acting upwards on the drill stem. A sensitive weight indicator will register this change as an increase in drill stem weight. For very large kicks, fluid may enter the annulus with enough force to cause a decrease in indicated string weight. At this point, you have probably left things too long and probably have a blowout on your hands.

Increase in Penetration Rate (Drilling Break)

A marked increase in rate of penetration (ROP) may indicate either changes in the type of formation being drilled or a reduction in the positive difference between the mud pressure and pore pressure.

Generally, the following parameters affect the ROP:

• Rock type
• Formation bulk density/porosity
• Difference between mud pressure and formation pore pressure
• Bit type/wear
• Hydraulics
• Weight on bit
• Rotary speed
• Personnel/equipment.

Drilling breaks (i.e. where the rate of penetration increases significantly) are generally evidence of porosity change. Drilling rate tends to decrease with depth. Thus when a drilling break occurs, it may be an evidence of transition to an abnormal zone. It is crucial at this point to stop drilling and check for flows.

Remember that the work of drilling is a combination of work done by the bit and the mud impact, combined with the effect of pore pressure. If the latter exceeds the downward pressure from the mud, as rock is removed, the pore pressure will tend to break down the formation and assist the work of drilling.

Surface Well Control Equipment

The control equipment is laid out as shown in Figure 1 and is made up of:

1. Blow out preventers - Usually mounted in a stack including annular and ram type preventers. Figure 2 is an example of a BOP stack arrangement of single ram units and annular unit for surface use, showing operation of different components. Figure 3 shows two different makes of annular BOP with varying sealing element design. Principles of operation are essentially the same in both cases; it is the method of deformation of the element that is different.
2. Drilling Spool (Figure 2) for attachment of high pressure choke and kill lines, for circulation with the BOP closed.
3. Casing head (Figure 2) - This is welded to the first surface casing and it provides support and pressure seal for the BOP stack and future casing strings.
4. Choke Manifold and Control Panel (Figure 4 and 5) - To control flow of produced fluids and route them to separator, flare or holding tank or pit. A typical choke manifold includes:
5. • One hydraulically operated BOP outlet valve for positive closure
   • Two to four adjustable chokes (variable-opening valves). One or more may be remotely actuated, the others are usually directly operated by handwheel
   • Several manual gate valves.
   • The adjustable chokes permit precise control of return flow rate and back pressure.
   • Kelly Cock, Float Valve or Inside BOP (Figure 6) - To prevent back flow via the drill pipe.
6. Mud/Gas separators and Degassers - Equipment for removing gas from mud.

For subsea well control equipment, the layout and configuration are rather different. They may include (Figures 7 and 8):

• Templates - Temporary and permanent guide bases
• Subsea BOP stack
• Marine riser, etc.

Figure 9 shows a double ram type BOP unit generally used in sub-sea BOP stacks, and examples of the internal components used in ram type BOPs.