Exercise 5 Maximum Allowable Annular Surface Pressure — MAASP
If a mudweight of 9.5ppg mud is required to drill the 12 1/4” hole section of the above well, the MAASP when drilling this hole section would be:
The maximum allowable mudweight in the next hole section (Exercise 3 above) is 13.95 ppg
The pressure at the casing shoe with 13.95 ppg mud :
13.95 x 0.052 x 7000 = 5078 psi
The pressure at the casing shoe with 9.5 ppg mud :
9.5 x 0.052 x 7000 = 3458 psi
The MAASP is therefore = 5078 — 3458 = 1620 psi
1. INTRODUCTION
2. PRIMARY CONTROL
2.1 Reduction in Mudweight
2.2 Reduced Height of Mud colom
3. warning signs of kicks
3.1 Primary Indicators of a Kick
3.2 Secondary Indicators
3.3 Precautions Whilst Drilling
3.4 Precautions during tripping
4. secondary control
4.1 Shut in Procedure
4.2 Interpretation of Shut-in Pressures
4.3 Formation Pore Pressure
4.4 Kill Mud Weight
4.5 Determination of the Type of Influx
4.6 Factors Affecting the Annulus Pressure, Pann 4.8 MAASP
5. WELL KILLING PRocEDuRES
5.1 Drillstring out of the Well
5.2 Drillstring in the Well
5.3 one circulation Well Killing Method
5.4 Drillers Method for Killing a Well
6. bop equipment
6.1 Annular Preventers
6.2 Ram Type Preventers
6.3 Drilling Spools
6.4 casing Spools
6.5 Diverter System
6.6 choke and Kill Lines
6.7 choke Manifold
6.8 choke Device
6.9 Hydraulic Power Package (Accumulators)
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6.10 Internal Blow-out Preventers
7. bop stack ARRANGEMENTS
7.1 General considerations
7.2 API Recommended Configurations
7.2.1 Low Pressure (2000 psi WP)
7.2.2 Normal Pressure (3000 or 5000 psi WP)
7.2.3 Abnormally High Pressure
(10000 or 15000 psi WP)
Having worked through this chapter the student will be able to : General:
• Describe and prioritise the implications of a blowout
• Define the terms: kick; blowout; primary and secondary control; BOP; BOP Stack
Primary Well Control:
• List and describe the common reasons for loss of primary control
• Describe the impact of gas entrainment on mudweight
• calculate the EcD of the mud and describe the impact of mudweight on lost circulation.
Kick Detection and control:
• List and describe the warning signs of a kick
• Identify the primary and secondary indicators and describe the rationale behind their interpretation.
• Describe the operations which must be undertaken when a kick is detected.
• Describe the precautions which must be taken when tripping
Secondary Control:
• Describe the procedure for controlling a kick when drilling and when tripping.
• Describe the one circulation and drillers method for killing a well.
• Describe the manner in which the drillpipe and annulus pressure vary when killing the well with both the one circulation and drillers method.
• Calculate: the formation pressure; the mudweight required to kill the well; and the density (nature) of the influx.
• Describe the implications for the annulus pressure of: the volume of the kick; a gas bubble rising in the annulus when shut-in
Well Control Equipment:
• Describe the equipment used to control the well after a kick has occurred
• Describe the ways in which the BOP stack can be configured and the advantages and disadvantages of each of the configurations.
This chapter will introduce the procedures and equipment used to ensure that fluid (oil, gas or water) does not flow in an uncontrolled way from the formations being drilled, into the borehole and eventually to surface. This flow will occur if the pressure in the pore space of the formations being drilled (the formation pressure) is greater than the hydrostatic pressure exerted by the colom of mud in the wellbore (the borehole pressure). It is essential that the borehole pressure, due to the colom of fluid, exceeds the formation pressure at all times during drilling. If, for some reason, the formation pressure is greater than the borehole pressure an influx of fluid into the borehole (known as a kick) will occur. If no action is taken to stop the influx of fluid once it begins, then all of the drilling mud will be pushed out of the borehole and the formation fluids will be flowing in an uncontrolled manner at surface. This would be known as a Blowout. This flow of the formation fluid to surface is prevented by the secondary control system. Secondary control is achieved by closing off the well at surface with valves, known as Blowout Preventers — BOPs.
The control of the formation pressure, either by ensuring that the borehole pressure is greater than the formation pressure (known as Primary Control) or by closing off the BoP valves at surface (known as Secondary Control) is generally referred to as keeping the pressures in the well under control or simply well control.
When pressure control over the well is lost, swift action must be taken to avert the severe consequences of a blow-out. These consequences may include:
• Loss of human life
• Loss of rig and equipment
• Loss of reservoir fluids
• Damage to the environment
• Huge cost of bringing the well under control again.
For these reasons it is important to understand the principles of well control and the procedures and equipment used to prevent blowouts. Every operating company will have a policy to deal with pressure control problems. This policy will include training for rig crews, regular testing of BOP equipment, BOP test drills and standard procedures to deal with a kick and a blow-out.
one of the basic skills in well control is to recognise when a kick has occurred. Since the kick occurs at the bottom of the borehole its occurrence can only be inferred from signs at the surface. The rig crew must be alert at all times to recognise the signs of a kick and take immediate action to bring the well back under control.
The severity of a kick (amount of fluid which enters the wellbore) depends on several factors including the: type of formation; pressure; and the nature of the influx. The higher the permeability and porosity of the formation, the greater the potential for a severe kick (e. g. sand is considered to be more dangerous than a shale). The greater the negative pressure differential (formation pressure to wellbore pressure) the easier it is for formation fluids to enter the wellbore, especially if this is coupled with high permeability and porosity. Finally, gas will flow into the wellbore much faster than oil or water
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