Well Control presentation for controlling oil wells.pptx

The single most important step to blowout prevention is closing the blowout preventers when thewell kicks.
The decision to do so may well be the most important of your working life.
It ranks with keeping the hole full of fluid as a matter of extreme importance in drilling operations.
The successful detection and handling of threatened blowouts (‘kicks’) is a matter of maximum importance to our company. Considerable study and experience has enabled the industry to develop simple and easily understood procedures for detecting and controlling threatened blowouts. It is extremely important that supervisory personnel have a thorough understanding of these procedures as they apply to Saudi Aramco operated drilling rigs.
The reasons for promoting proper well control and blowout prevention are overwhelming. An
uncontrolled flowing well can cause any or all of the following:
• Personal injury and/or loss of life
• Damage and/or loss of contractor equipment
• Loss of operator investment
• Loss of future production due to formation damage
• Loss of reservoir pressures
• Damage to the environment through pollution
• Adverse publicity
• Negative governmental reaction, especially near populated areas
Hydrostatic Pressure
All vertical columns of fluid exert hydrostatic pressure. The magnitude of the hydrostatic pressure is determined by the height of the column of fluid and the density of the fluid. It should be remembered that both liquids and gases could exert hydrostatic pressure. The hydrostatic pressure exerted by a column of fluid can be calculated using Equation A.1. While drilling ahead, the hydrostatic pressure exerted by the drilling mud is our number one defense against taking kicks.
Pressure Gradient
When comparing fluid densities and hydrostatic pressures, it is often useful to think in terms of a pressure gradient. The pressure gradient associated with a given fluid is simply the hydrostatic pressure per vertical foot of that fluid. Heavier (more dense)
fluids have higher-pressure gradients than lighter fluids. The pressure gradient of a given fluid can be calculated with the formula given in Equation A.2.
. Formation Pressure

Formation pressure is the pressure contained inside the rock pore spaces.
Knowledge of formation pressure is important because it will dictate the mud hydrostatic pressure and therefore the mud weight required in the well.
If the formation pressure is greater than the hydrostatic pressure of the mud column, fluids (gas, oil or salt water) can flow into the well from permeable formations
Surface Pressure

We use the term surface pressure to describe any pressure that is exerted at the top of a column of fluid. Most often we refer to surface pressure as the pressure, which is observed at the top of a well. Surface pressure may be generated from a variety of sources including downhole formation pressures, surface-pumping equipment, or surface chokes.
Bottomhole Pressure

Bottomhole pressure is equal to the sum of all press.

1. Well Control Students Name: عبدالعزيز نواف العتيبى تركى عبدالله العتيبى

2. Table of Content Introduction Understanding of Pressures Causes of Kicks Detection of Kicks Well Killing Procedures Other Well Control Methods

3. 1. Introduction The single most important step to blowout prevention is closing the blowout preventers when thewell kicks. The decision to do so may well be the most important of your working life. It ranks with keeping the hole full of fluid as a matter of extreme importance in drilling operations.

4. 1. Introduction The successful detection and handling of threatened blowouts (‘kicks’) is a matter of maximum importance to our company. Considerable study and experience has enabled the industry to develop simple and easily understood procedures for detecting and controlling threatened blowouts . It is extremely important that supervisory personnel have a thorough understanding of these procedures as they apply to Saudi Aramco operated drilling rigs.

5. 1. Introduction The reasons for promoting proper well control and blowout prevention are overwhelming. An uncontrolled flowing well can cause any or all of the following: • Personal injury and/or loss of life • Damage and/or loss of contractor equipment • Loss of operator investment • Loss of future production due to formation damage • Loss of reservoir pressures • Damage to the environment through pollution • Adverse publicity • Negative governmental reaction, especially near populated areas

6. 2. Understanding of Pressures 2.1. Hydrostatic Pressure All vertical columns of fluid exert hydrostatic pressure. The magnitude of the hydrostatic pressure is determined by the height of the column of fluid and the density of the fluid. It should be remembered that both liquids and gases could exert hydrostatic pressure. The hydrostatic pressure exerted by a column of fluid can be calculated using Equation A.1. While drilling ahead, the hydrostatic pressure exerted by the drilling mud is our number one defense against taking kicks.

7. 2. Understanding of Pressures 2.2. Pressure Gradient When comparing fluid densities and hydrostatic pressures, it is often useful to think in terms of a pressure gradient. The pressure gradient associated with a given fluid is simply the hydrostatic pressure per vertical foot of that fluid. Heavier (more dense) fluids have higher-pressure gradients than lighter fluids. The pressure gradient of a given fluid can be calculated with the formula given in Equation A.2.

8. 2. Understanding of Pressures 2.3. Formation Pressure Formation pressure is the pressure contained inside the rock pore spaces. Knowledge of formation pressure is important because it will dictate the mud hydrostatic pressure and therefore the mud weight required in the well. If the formation pressure is greater than the hydrostatic pressure of the mud column, fluids (gas , oil or salt water) can flow into the well from permeable formations

9. 2. Understanding of Pressures 2.4. Surface Pressure We use the term surface pressure to describe any pressure that is exerted at the top of a column of fluid. Most often we refer to surface pressure as the pressure, which is observed at the top of a well. Surface pressure may be generated from a variety of sources including downhole formation pressures, surface-pumping equipment, or surface chokes.

10. 2. Understanding of Pressures 2.5. Bottomhole Pressure Bottomhole pressure is equal to the sum of all pressures acting in a well. Generally speaking , bottomhole pressure is the sum of the hydrostatic pressure of the fluid column above the point of interest, plus any surface pressure, which may be exerted on top of the fluid column, plus any annular friction pressure. This concept is expressed mathematically in Equation A.3.

11. 2. Understanding of Pressures 2.6. Equivalent Circulating Density When circulating fluid in a wellbore, frictional pressures occur in the surface system, drill pipe, bit and in the annulus, which in turn are reflected in the standpipe pressure. As also discussed, these frictional pressures always act opposite to the direction of flow . When circulating conventionally, or the “long way”, all the frictional pressures, including annular friction, act against the pump. The annular friction, or annular pressure loss as it is sometimes referred to, acts against the bottom of the wellbore, which results in an increase in bottomhole pressure. This is known as Equivalent Circulating Density, or ECD. ECD

12. 2. Understanding of Pressures 2.7. Differential Pressure In well control, differential pressure is the difference between the bottomhole pressure and the formation pressure. The differential is positive if the bottomhole pressure is greater than the formation pressure, which creates what is called an ‘overbalanced ’ condition. 2.8. Choke Pressure Choke pressure is the pressure loss created by directing the return flow from a shutin well through a small opening or orifice for the purpose of creating a backpressure on the well while circulating out a kick. The choke or back pressure can be thought of as a frictional pressure loss which will be imposed on all points in the circulating system , including the bottom of the hole.

13. 2. Understanding of Pressures 2.9. Swab and Surge Pressures Swab pressure is the temporary reduction in the bottomhole pressure that results from the upward movement of pipe in the hole. Surge pressure is the opposite effect, whereby wellbore pressure is temporarily increased as pipe is run into the well . 2.10. Fracture Pressure The formations penetrated by the bit are under considerable stress, due to the weight of the overlying sediments. If additional stress is applied while drilling, the combined stresses may be enough to cause the rock to fail or split, allowing the loss of whole mud to the formation. Fracture pressure is the amount of borehole pressure that it takes to split or fail a formation.

14. 3. Causes of Kicks A kick is defined as any undesirable flow of formation fluids from the reservoir to the wellbore , which occurs as a result of a negative pressure differential across the formation face . Wells kick because the reservoir pressure of an exposed permeable formation is higher than the wellbore pressure at that depth. There are many situations, which can produce this unfavorable downhole condition. Among the most likely and recurring are: • Low Density Drilling Fluid • Abnormal Reservoir Pressure • Swabbing • Not Keeping the Hole Full on Trips • Lost Circulation

15. 3. Causes of Kicks 3.1. Low Density Drilling Fluid The density of the drilling fluid is normally monitored and adjusted to provide the hydrostatic pressure necessary to balance or slightly exceed the formation pressure. Accidental dilution of the drilling fluid with makeup water in the surface pits or the addition of drilled-up, low density formation fluids into the mud column are possible sources of a density reduction which could initiate a kick. Diligence on the mud pits is the best way to insure that the required fluid density is maintained in the fluids we pump downhole .

16. 3. Causes of Kicks 3.2. Abnormal Reservoir Pressure Formation pressure is due to the action of gravity on the liquids and solids contained in the earth's crust. If the pressure is due to a full column of salt water with average salinity for the area, the pressure is defined as normal. If the pressure is partly due to the weight of the overburden and is therefore greater, the pressure is known as abnormal . Pressures below normal due to depleted zones or less than a full fluid column to the surface are called sub normally pressured.

17. 3. Causes of Kicks 3.3. Swabbing Swabbing is a condition, which arises when pipe is pulled from the well and produces a temporary bottomhole pressure reduction. In many cases, the bottomhole pressure reduction may be large enough to cause the well to go underbalanced and allow formation fluids to enter the wellbore. By strict definition, every time the well is swabbed in, it means that a kick has been taken. While the swab may not necessarily cause the well to flow or cause a pit gain increase, the well has produced formation fluids into the annulus, which have almost certainly lowered the hydrostatic pressure of the mud column.

18. 3. Causes of Kicks 3.4. Not Keeping Hole Full Blowouts that occur on trips are usually the result of either swabbing or not keeping the hole full of mud. Much progress has been made in prevention, but constant vigilance must be maintained. As drill pipe and drill collars are pulled from the hole during tripping operations, the fluid level in the hole drops. In order to maintain fluid level and mud hydrostatic pressure, a volume of mud equal to the volume of steel removed must be pumped into the annulus. An accurate means of measuring the amount of fluid required to fill the hole must be provided.

19. 3. Causes of Kicks 3.5. Lost Circulation An important cause of well kicks is the loss of whole mud to natural and/or induced fractures and to depleted reservoirs. A drop in fluid level in the wellbore can lower the mud hydrostatic pressure across permeable zones sufficiently to cause flow from the formation. Some of the more common causes of lost circulation include : High Mud Weight, Going into Hole Too Fast, Pressure Due to Annular Circulating Friction, Sloughing or Balled-Up Tools. Mud-Cap Drilling.

20. 4. Detection of Kicks It is highly unlikely that a blowout or a well kick can occur without some warning signals. If the crew can learn to identify these warning signals and to react quickly, the well can be shut in with only a small amount of formation fluids in the wellbore. Smaller kick volumes decrease the likelihood of damage to the wellbore and minimize the casing pressures. Kick indicators are classified into two groups; positive and secondary. Any time the well experiences a positive indicator of a kick, immediate action must be taken to shut in the well . When a secondary indicator of a kick is identified, confirmation steps should be taken to verify if the well is indeed kicking.

21. 4. Detection of Kicks 4.1. Positive Indicators of a Kick The “Positive Indicators of a Kick” are shown to the left. Immediate action should be taken to shut-in the well whenever these indicators are experienced . It is not recommended to check for flow after a positive indicator or has been identified .

22. 4. Detection of Kicks 4.2. Secondary Indicators of a Kick The “Secondary Indicators of a Kick” are shown to the left. The occurrence of any of these indicators should alert the Drilling Foreman that the well may be kicking, or is about to kick. These indicators should never be ignored. Instead , once realized, steps should be taken to determine the reason for the indication (indicating a flow check if necessary).

23. 4. Detection of Kicks 4.3. Indicators of Abnormal Pressure “Indicators of Abnormal Pressure” are shown to the left. Observance of any of these indicators often means that the well is penetrating an abnormally pressured formation. Remedial action may range from increasing the mud weight to setting casing.

24. 4. Detection of Kicks 4.4. Other indications Useful for Kick detection Increase in Pit Volume Increase in Flow Rate Decrease in Circulating Pressure Gradual Increase in Drilling Rate Drilling Breaks Increase in Gas Cutting Increase in Chlorides Decrease in Shale Density

25. 5. Well Killing Procedures 5.1. The Driller’s Method The Driller’s Method of well control requires two complete and separate circulations of the drilling fluid in the well. The first circulation removes the influx from the annulus using the mud density in the hole at the time of the kick. Casing pressure is held constant until the pump is at kill rate. Then drillpipe pressure is held constant to maintain bottomhole pressure equal to, or slightly greater than formation pressure. If the kick contains gas, it will expand in the annulus under controlled conditions as it nears the surface . Therefore an increase in casing pressure and pit volume should be expected. Drill pipe pressure and pump rate must be held constant. At any time during or immediately after this first circulation, the well can be shut in and the drillpipe pressure will read the same as it did originally.

26. 5. Well Killing Procedures 5.1. The Driller’s Method (Cont.) After the kick fluid has cleared the choke, the well can be shut in. At this time, shut-in drillpipe and casing pressures will be the same, assuming all of the influx has been removed and mud hydrostatic is the same inside the drillpipe and the annulus. The original shut-in drillpipe pressure is converted to an equivalent density at the bit, and the mud density is increased accordingly.

27. 5. Well Killing Procedures 5.1. The Driller’s Method (Cont.) During the second circulation, bottomhole pressure is held constant by first maintaining casing pressure equal to the shut-in value while filling the drillpipe with the kill mud. When the drill pipe is filled, as determined by the number of strokes pumped, the drill pipe pressure is recorded and control shifts to maintaining a constant drill pipe pressure while the annulus is filled with heavy mud. When the kill mud reaches the surface , the pressure on the choke should be minimal. The pumps can be stopped while holding casing pressure constant and the well checked for flow.

28. 5. Well Killing Procedures 5.1. The Driller’s Method (Cont.) Any time a well under pressure is circulated, the start-up and shutdown procedures are critical and should be done with exceptional care. Whenever the pump speed is increased or decreased (including start-up and shutdown) the casing pressure must be held constant at the value it had immediately before the pump speed change was initiated. This ensures that bottomhole pressure remains constant. This procedure is valid because casing pressure should be the same whether the well is closed-in or being pumped. However, the drillpipe pressure must vary depending upon the circulating pressure loss in the system, which is a function of the pump speed. The casing pressure cannot be held constant for very long though due to the changing height of the influx caused by the irregular annulus and gas expansion.

29. 5. Well Killing Procedures 5.2. The Engineer’s Method The Engineer’s Method of well control requires only one complete circulation . The kill mud is circulated at the same time the influx is removed from the annulus. After the well has been shut in, the pressures recorded, and pit volume increase recorded, the mud density in the pits is increased and a drillpipe pressure schedule is created. The schedule must be prepared in order that drillpipe pressure can be properly adjusted downward as kill mud fills the drillpipe .

30. 5. Well Killing Procedures 5.2. The Engineer’s Method (Cont.) Once the kill mud reaches the bit, the drillpipe pressure should be held constant until kill mud reaches the surface. Bottomhole pressure will be equal to, or slightly greater than formation pressure throughout the procedure as long as pump rate is maintained at the predetermined rate.

31. 6. Other Well Control Methods 6.1. The Volumetric Control Method This method is used when the pumps are inoperative or when the drillpipe is either out of the hole, plugged, or has a hole in it. This is not a kill method but simply a method of controlling bottomhole and surface casing pressures as the gas migrates up the hole. The gas is allowed to expand as it migrates up the hole. A (relatively ) constant bottomhole pressure is maintained by bleeding off mud with an equivalent hydrostatic head equal to the rise in pressure caused by the migrating gas . The basis of the method is equating pit volume change and annulus pressure .

32. 6. Other Well Control Methods 6.2. The Low Choke Pressure Method This method is used if pressures threaten to become excessive while a well is being killed. Choke pressure must be reduced sufficiently to prevent casing burst or formation breakdown while circulating out. In kick situations requiring weight increases , the mud weight should be increased as soon as practical. Kicks occurring while drilling tight formations or after trips where tight formations have been drilled may be circulated out using this method without increasing the mud weight.

33. 6. Other Well Control Methods 6.3. Bullheading If normal well killing techniques with conventional circulation are not possible or will result in critical well control conditions, bullheading may be considered as a useful method to improve the situation. Mud/influx are displaced/squeezed back downhole into the weakest exposed open hole formation.