Day 2 IWCF

An Overview to IWCF Well Control Certification Course (DRILLER/SUPERVISOR LEVEL)

Day 2

Prepared by: Engr. Muhammad Nauman Awan

Table of Contents DAY-2 ----- Session – I ............................................................................................................................. 5 Gas influx behavior ....................................................................................................................................... 5 Open well migration, Bottom hole pressure reduces .................................................................................... 5 Gas bubble pressure reduces, Closed-in (Shut-in) conditions migration ...................................................... 6 Well killing Driller's method ........................................................................................................................ 8 Preparation of kill sheet ................................................................................................................................ 9 Advantages and Disadvantages of the Driller's method.............................................................................. 10 Procedures(driller's method), Closing in the well ....................................................................................... 10 Pressure and pit volume readings, First circulation .................................................................................... 11 Selecting the pump rate, Standpipe pressure during first circulation .......................................................... 11 Determining the height and gradient of the influx, travel times, Standpipe kill graph .............................. 11 Determining the pressure at the top of influx, First circulation-Action ...................................................... 12 Second circulation-Determining the gradient of the kill mud ..................................................................... 12 Determining the amount of overbalance, Selecting pump rate, Travel times ............................................. 12 Standpipe pressure, Second circulation-Action .......................................................................................... 13 Procedure after the well has been brought under control ............................................................................ 13 Crewmember responsibilities for shut-in, Bottom hole pressure change.................................................... 14 Establish Circulation in Driller’s Method ................................................................................................... 16 Additional Topics, Equivalent circulating density(ECD) ........................................................................... 17 Volumetric Well Control, Boyle’s Law, Hydrostatic pressure ................................................................... 17 Gas Behavior and Bottom Hole Pressure in a Shut in well......................................................................... 20

DAY-2 ----- Session - II ......................................................................................................................... 22 Wait and Weight Method, Advantages and Disadvantages of the Wait and Weight method .................... 22 Procedure and Calculations, Initial, Final circulating pressure, Bit strokes, Time to pump ....................... 22 Wait and Weight Well Control Method (Engineer’s Method), Maximum pit gain .................................... 23 Maximum Surface Pressure ....................................................................................................................... 25 Formation Pressure from Kick Analysis .................................................................................................... 26 Drill Pipe Pressure Calculation, Determine kill weight mud, Slow Circulating Rate (SCR) .................... 27 Determine Final Circulating Pressure (FCP), Stroke from surface to bit, Step down table ....................... 28 Pressure Profile of Drillpipe and Casing Pressure, Casing Pressure ......................................................... 29 Volumetric Well Control method .............................................................................................................. 30 Annular Capacity Factor (ACF), Mud Increment (MI) .............................................................................. 31 Lubrication or Top kill, Conventional Lubrication .................................................................................... 32

Stripping (using Annular Preventer) .......................................................................................................... 33 Snubbing , Stripping using ram preventer .................................................................................................. 34 Annular BOP, Ram type BOP .................................................................................................................... 35 Controls bottom hole pressure in W&W, Displace kill weight mud(mud to the bit, bit to surface)........... 36 Additional Topics, Methods of well kill, Well Shut-in............................................................................... 38 Shut-in procedures, Pump Output Calculation ........................................................................................... 39 DAY-2 ----- Session - III ........................................................................................................................ 42 Unusual situations in well control, Plugged or washed bit nozzles ............................................................ 42 Plugged Chokes, Change in Circulating Kill Rate ...................................................................................... 42 Complete Power Failure, Choke Washout, Depth of Washout ................................................................... 43 Unusual Well-Control Operations (Practical Well Control by Ron Baker) ........................................ 45 Washed out, Plugged bit ............................................................................................................................. 45 Other Problems, Pressure between Casing Strings ..................................................................................... 46 Pump Failure ............................................................................................................................................... 47 BOP Failure, Flange Failure, Weep-hole Leakage, Failure to Close .......................................................... 48 Failure of BOP Seals, Flow problems, Pressure Gauge failure, ANNULUS Blocked .............................. 49 Pipe Off bottom, Pipe out of the hole, float in the drill stem ...................................................................... 50 Stripping and Snubbing operations, Preparing for Stripping ..................................................................... 51 Stripping into the Hole, Stripping in with Annular Preventer ................................................................... 52 Stripping in with Ram Preventers .............................................................................................................. 54 Stripping Out of the Hole, Snubbing ......................................................................................................... 55 Snubbing Units(Mechanical, Hydraulic), Pipe reciprocation during a well kill ........................................ 56 Lost Circulation, Conditions(Bad Cement Jobs, Induced Fractures, Fractured Formations) ..................... 57 Well Control with Partial Lost Returns, Barite Plugs ................................................................................ 58 Gunk Plugs .................................................................................................................................................. 60 Excessive Casing pressure, Bullheading ..................................................................................................... 61 Snubbing into the drill stem ....................................................................................................................... 62 Underbalanced Drilling, Rotating Heads, Rotating Annular Preventers ................................................... 63 Other special well-control considerations(Slim Holes, Tapered Holes and Tapered Strings) .................... 63 Horizontal well-control considerations ....................................................................................................... 64 Killing Horizontal Wells ............................................................................................................................ 66 Procedure for Off-Bottom Kill, Gas Behavior in Horizontal Section ........................................................ 66 Thief and kick zone combinations ............................................................................................................. 67

DAY-2 ---- Session - IV ......................................................................................................................... 69

Lost circulation, Zones, Causes, Induced fractures .................................................................................... 69 Cavernous formations, Prevention of lost circulation ................................................................................. 70 Preventive tests, Leak off test (LOT), Formation integrity test (FIT), Remedial measures ....................... 71 Use of loss of circulation materials ............................................................................................................ 72 Control operations - With heavy mud, With barite plug ............................................................................ 73 Barite Plug - Fresh Water Slurry, Barite Plug Preparation, Setting Barite Plug ........................................ 74 Control operations - With gunk plug, Blowout Preventer, Annular Preventers ......................................... 76 How the annular preventers work? ............................................................................................................ 77 Ram Preventers, Pipe Rams, Blind Rams, Blind Shear Rams .................................................................... 80 BOP Stack Organization and BOP Stack Arrangement ............................................................................. 83 Blow-out Preventers Stack Arrangements ................................................................................................. 84 BOP’s Control System, Accumulators, Pumps .......................................................................................... 85 Charging Pumps, Fluid Reservoir, Manifold and Piping ............................................................................ 86 Choke manifold, Choke line, Choke Manifold Control Console ............................................................... 86 Standpipe Manifold, Kill Manifold, Choke Manifold................................................................................. 87 Tripping Procedures, Driller’s Method Vs Wait and Weight, Comparison ............................................... 89 Deviated hole / tapered drill string, Hole problems, Fluid mixing capability of rigs ................................. 91 Drilling in formations with ballooning potential ....................................................................................... 92 Complications and friction changes during well control ............................................................................ 92 Time to kill well, Shoe Pressure ................................................................................................................. 93 Maximum casing pressure at surface (PcMax) and peak gas flow rate ..................................................... 94 CONCLUSION, Appendix ........................................................................................................................ 95

DAY-2 --------------- Session – I Gas influx behavior When a well is shut in on a kick that contains gas the gas will percolate or migrate up the hole even if the well is allowed to remain static. Gas migration can cause confusion during a well control operation, because it can be overlooked. Gas or Gas bubbles float or migrate up the hole because they are lighter than mud. When gas bubbles rise they expand or if they are not allowed to expand they cause an increase on all wellbore pressures and surface pressures. Therefore if a well is shut in for a long time, all pressures, wellbore surface etc. will increase causing lost circ. etc., if not relieved by allowing gas to expand. So lowering SIDPP to original value through choke and observing, keeping SIDPP at original value, will prevent this problem. All pressures will increase during migration of gas except pressure in actual bubble which is usually at formation pressure. If a gas bubble is allowed to expand without control of any kind it will eventually unload the well. With the well unloaded, kick sizes increasing, causing more unloading. This cycle of influx and unloading has caused the loss of many wells. Boyles Law is shortened version of equation for gas expansion e.g. P1V1 = P2V2. It generally states that if the volume of gas doubles, the pressure is reduced by half in the bubble. P1 = Hydrostatic Pressure (W/Gas bubble on bottom) =T.D V1 = Original Pit Gain P2 = Hydrostatic press at secondary depth V2 = Gas volume @ surface or at secondary depth V2 = P1V1/P2 Open well migration The effect of gas migration in an open hole is mentioned below: • Bottom hole pressure reduces • Gas bubble pressure reduces • Pressure below the bubble reduces • Pressure above the bubble remains constant We shall discuss each point one by one. A. BOTTOM HOLE PRESSURE REDUCES • In open well when wellbore takes a kick, BHP = Hyd. Pr. of Mud in Annulus + Hyd. Pr. of Kick • As the kick migrates upward, it expands and unloads mud from the annulus to the pit. • Thus mud volume in annulus decreases.

• Also due to expansion of kick, the average density of mud column in annulus reduces resulting in reduction in hydrostatic pr. • This justifies that "Bottom hole pressure reduces as kick migrates up in the open hole". B. GAS BUBBLE PRESSURE REDUCES During open hole gas migration, gas bubble moves upwards continuously and the hydrostatic column of mud above gas bubble goes on decreasing. The decrease in hydrostatic pressure above gas bubble facilitates gas bubble to expand. • Using Gas Equation: P1 V1 = P2 V2, thus, P2 = (P1 V1)/ V2. • Now consider a situation when kick is at bottom. Its pressure = P1 and volume = V1. • At some height above, the gas expands and now its pressure = P2 and Volume = V2. • Using gas equation: P2 = (P1 V1)/ V2. • Since V2 increases due to gas expansion, P2 will reduce. Thus in open hole gas migration, GAS BUBBLE PRESSURE REDUCES as gas migrates upward.

Closed-in (Shut-in) conditions migration Gas migration is the movement of low-density fluids up the annulus. It tends to build pressure at the surface, if time is allowed for migration. Also, the influx may have a tendency to deteriorate the hole stability and cause either stuck pipe or hole bridging. These problems must also be considered when reading the shut-in pressures.

Closed-in (Shut-in) conditions circulating

Well killing Driller's method Driller’s method is one of several methods to kill the well. The main idea of driller method is to kill the well with constant bottom hole pressure. The Driller’s Method of well control requires two complete and separate circulations of drilling fluid in the well. The first circulation removes influx with original mud weight. When starting to bring pumps up to speed, casing pressure must be held constant until kill rate is reached. Then drillpipe pressure is held constant to maintain constant bottomhole pressure which is normally equal to, or slightly greater than pore pressure. Drillpipe pressure will be held constant until influx is removed from annulus. If the wellbore influx is gas, it will expand when it comes close to surface therefore you will see an increase in pit volume and casing pressure. After the kick is totally removed from the well, when the well is shut-in, drillpipe and casing pressure will be the same value. If not, it means that there is influx still left in the wellbore or trapped pressure. Before going to the second circulation, we need to know kill mud weight which can be calculated from initial shut-in drillpipe pressure. The calculation part will be discussed as in next section. Second circulation kills well with kill mud. When the required kill mud weight is mixed, it is the time to start the second circulation of driller method. We start with bringing pumps to kill rate by holding casing pressure constant. While circulating with the kill mud, casing pressure must be held constant until kill mud reaches the bit. After that, we need to hold drill pipe pressure constant then continue circulating with constant drill pipe pressure until kill mud weight reaches at surface. Then shut down pumping operation and observe drillpipe and casing pressure. If the well is successfully killed, both drillpipe and casing pressure will be zero. If not, there is some influx still in the well.

Preparation of kill sheet

Well Control - Driller's Method With this method, the well is killed in two circulations. During the first circulation: the influx is circulated out of the hole using the existing mud. Additional influx is prevented by adjusting the choke to maintain a constant bottom hole pressure slightly in excess of the pore pressure. During the second circulation: the existing mud is replaced by mud of the required density to (over)balance the pore pressure. The choke is adjusted to maintain a constant bottom hole pressure slightly greater than the pore pressure.

1. Disadvantages of the driller's method Compared with the balanced mud method, principal disadvantages of the driller's method include the following:  ·the well must remain closed-in under pressure longer;  ·the maximum pressure at the casing shoe and against the formation will be higher if the influx is gas (unless the top of the gas reaches the casing shoe before the drillstring would be displaced by heavy mud in the balanced mud method);  ·the maximum choke pressure when the top of the influx reaches the surface will be higher if the influx is gas. Before employing the driller's method, it is essential to confirm that exposed formations can support the higher pressures which might be developed during the first circulation. 2 Advantages of the driller's method Advantages of the driller's method include the following:  Simplicity: circulation can be started without calculations. This may be useful if expert supervision is not immediately available;  Pumping can begin as soon as drillpipe pressure build-up is established; there is no delay whilst mud is weighted up. This could be important in case of an H2S influx;  The well can be effectively controlled (although not killed), even if the weighting material supply is inadequate. 2.1 Procedures The following procedures concerning the driller's method are discussed:  ·Closing in the well.  ·Pressure and pit volume readings.  ·First circulation: selecting the pump rate.  ·Standpipe pressure during first circulation.  ·Determining the height and gradient of the influx.  ·First circulation: determining travel times (or volumes).  ·First circulation: standpipe kill graph construction and use.  ·Determining the pressure at the top of a gas influx at any point in the annulus.  ·First circulation: action.  ·Second circulation: determining the gradient of the kill mud.  ·Second circulation: determining the amount of overbalance.  ·Second circulation: selecting pump rate.  ·Second circulation: travel times (or volumes).  ·Second circulation: standpipe pressures.  ·Second circulation: standpipe kill graph construction and use.  ·Second circulation: action.  ·Procedure after the well has been brought under control. 3 Closing in the well Close in the well immediately after detecting a kick condition. The procedure is as for the balanced mud method.

4 Pressure and pit volume readings Pressure and pit volume readings should be taken as for the balanced mud method 5 First circulation: Selecting the pump rate The mud is not weighted up for the first circulation: therefore, the pump rate is not limited by the weighting material mixing capacity of the rig. However, the maximum pump rate is limited by other factors such as the increased initial standpipe pressure, the need for choke adjustment, and surface gas handling equipment. Also, if the choke starts blocking-off, pressure surges will be less at reduced circulating rates. Normally, the pump speed selected will not exceed 50% of the usual circulating rate applied for drilling operations. 6 Standpipe pressure during first circulation The standpipe pressure at the start is the same as with the balanced mud method. The standpipe pressure should then be approximately equal to the normal pre-kick circulation pressure at the selected pump speed, plus the closed-in drillpipe pressure, plus a small margin of 700 kPa (100 psi). Always make sure that the formation strength at the casing shoe is not exceeded during the circulating process. Since there is no change in the gradient of the mud being pumped, the initial standpipe pressure must be held constant throughout the first circulation to ensure that the bottom hole pressure is also kept constant. 7 Determining the height and gradient of the influx This information is not essential, but will give an indication of the pattern of choke pressures and pit level changes that may be expected during the first circulation. The procedure is as for the balanced mud method. 8 First circulation: Determining travel times (or volumes) The bit-to-shoe and shoe-to-choke times are determined .The total pumping time for the first circulation is that required to displace the annulus, i.e. the sum of the bit-to-shoe and shoe-tochoke times, volumes, or pump strokes. 9 First circulation: Standpipe kill graph construction and use The standpipe kill graph is a horizontal line equal to the closed-in drillpipe pressure plus the circulating pressure plus the overbalance margin of 100 psi. 10 Determining the pressure at the top of a gas influx at any point in the annulus When a gas kick is being circulated out of the hole, the influx volume will increase due to expansion and consequently results in increased pit levels. By calculating the expected annular pressures at the top of the influx at specific points along the hole together with the associated influx volumes at these points, comparisons can be made with actual values observed during circulating out the influx. This information can play an important role in the decision making process during well control operations. The pressure at the top of a gas bubble at any point in the annulus while circulating it out using the "Driller's method" can be calculated as follows:

11 First circulation: Action The procedure for the first circulation is as follows: 1. Open the choke and start pumping the existing mud at the selected pump speed. 2. Adjust the choke opening until the choke pressure equals the closed-in annulus pressure plus the overbalance margin. Record the choke pressures throughout the first circulation. 3. Read the standpipe pressure. It should agree with the calculated value, i.e. the normal pre-kick pump test circulation pressure at the selected pump speed plus the closed-in drillpipe pressure, plus a small margin of 700 kPa (100 psi). If the observed standpipe pressure does not agree with the calculated value, consider the observed pressure to be correct. 4. Note the standpipe pressure and thereafter keep it constant whilst maintaining a constant pump rate, until the influx is circulated out. 5. When all influx has been circulated out, stop the pump and close in the well to check the closed-in drillpipe and annulus pressures. At the end of the first circulation, the closed-in pressures of the annulus and drillpipe should be the same and equal to the initial closed-in drillpipe pressure. The well is controlled but not killed. During the first circulation the following should also be carried out:  ·maintain and record the density of the mud pumped into the drillstring. Ensure that it has  

the correct value; ·measure and record the properties of the mud returns; ·de-gas, treat or discard any contaminated mud returns.

12 Second circulation: Determining the gradient of the kill mud The gradient of the kill mud to balance the formation pressure can be determined as soon as the closed-in standpipe pressure has stabilized. A trip margin can now be added to the kill mud gradient in order to overbalance the formation pressure and to resume normal operations. 13 Second circulation: Determining the amount of overbalance Normally the overbalance on bottom during well control (neglecting friction losses in the annulus), should not exceed 700 kPa (100 psi). However, since the influx has been displaced with r1 mud during the first circulation, large fluctuations in mud gradient and choke control operations are not expected and therefore, if possible, the density of the mud in the well is raised directly to that required to resume normal operations. 14 Second circulation: Selecting pump rate This is carried out as for the balanced mud method. A constant pump rate, approximately one half the speed used for the drilling operation, is maintained during the second circulation. 15 Second circulation: Travel times (or volumes) Provided that the same pump rate is used, the surface-to-bit and bit-to-choke times are the same as for the balanced mud method Section 16 Second circulation: Standpipe pressure The initial standpipe pressure should be the same as for the first circulation.

Pst =Pdp + Pc1 + margin During the period that the heavy mud (including the overbalance) is pumped down the drillstring, the standpipe pressure should decrease until the heavy mud reaches the bit at which time it should be: Pst = Pc1 * rho2 / rho1 = Pc2 The standpipe pressure should remain constant after the heavy mud has reached the bit. 17 Second circulation: Standpipe kill graph construction and use The standpipe pressure kill graph for the second circulation is similar to that of the balanced mud method The procedure for constructing the standpipe kill graph is as follows: 1. Plot the initial circulating pressure plus margin at the start of the second circulation. 2. Plot the heavy mud circulating pressure (Pc2) at the time that the heavy mud reaches the bit. 3. Whilst the heavy mud is being circulated into the annulus, the back pressure should be progressively reduced to zero at the time when the heavy mud reaches the choke. The standpipe pressure should then equal the heavy mud circulating pressure. This assumes that the heavy mud gradient includes a suitable overbalance margin. 18 Second circulation: Action If possible, the density of the mud in the well is raised directly to that required to resume normal operations. The procedure during the second circulation is as follows: 1. Open the choke and start pumping mud of the required density at the rate selected to kill the well. Maintain a constant pumping rate. 2. Adjust the choke opening until the choke pressure equals the closed-in annulus pressure plus margin observed at the end of the first circulation. Choke pressures should be recorded throughout the process. 3. Read the standpipe pressure. This should agree with the calculated standpipe pressure, i.e. the pre-kick pump test circulating pressure plus the closed-in drillpipe pressure at the end of the first circulation including the margin. If the standpipe pressure does not agree with the calculated value, consider the observed pressure to be correct and modify the standpipe pressure kill graph accordingly. 4. When the heavy mud reaches the surface, stop pumping and check whether the well is dead. During the second circulation the following should also be carried out: ·maintain and record the density of the mud pumped into the drillstring; ensure that it has the correct value;  ·measure and record the properties of the mud returns until the well is killed;  ·de-gas, treat or discard any contaminated mud returns. 19 Procedure after the well has been brought under control After the well has been brought under control, the well should be flow-checked via the open choke line. The preventers can be opened and normal circulation resumed after any possible flow has ceased from the choke line for a reasonable flow-check time. Procedures for floating drilling operations are described in the balanced mud method.

Crewmember responsibilities for shut-in (Well Killing) procedures Each crewmember has different responsibilities during shut-in procedures. These responsibilities follow and are listed according to job classification. Floorhand (roughneck) These responsibilities for shut-in procedures belong to the floorhand: 1. Notify the driller of any observed kick-related warning signs. 2. Assist in installing the full-opening safety valve if a trip is being made. 3. Initiate well-control responsibilities after shut-in. Derrickman These responsibilities for shut-in procedures belong to the derrickman: 1. Notify the driller of any observed kick-related warning signs. 2. Initiate well-control responsibilities. 3. Begin mud-mixing preparations. Driller These responsibilities for shut-in procedures belong to the driller: 1. Immediately shut in the well if any of the primary kick-related warning signs are observed. 2. If a kick occurs while making a trip, set the top tool joint on the slips and direct the crews in the installation of the safety valve before closing the preventers. 3. Notify all proper company personnel.

Bottom hole pressure change while performing well control operation with driller’s method In the first circulation of driller’s method, driller circulates gas kick with 25 spm and the initial circulating pressure (ICP) is 1600 psi. The initial shut in drill pipe pressure is 450 psi. After shift change, another driller accidentally changes pump rate to 30 spm but he still holds drill pipe pressure constant. What will happen to bottom hole pressure? Let’ start with the basic formula ICP = SIDDP + SCR When the pump speed is increased, slow circulating rate (SCR), which is caused by friction, will increase in order to maintain constant bottom hole pressure. However, for this case, the drill pipe pressure is maintained constant with while increasing pump rate therefore the bottom pressure will decrease. How much bottom hole pressure will decrease? Current SCR = ICP – SIDPP = 1600 – 450 = 1150 psi

New SCR = 1656 psi With new pump rate at 30 spm, the new SCR should be 1656psi but the driller maintains the old SCR, 1150 psi. Therefore, the bottom hole pressure will decrease by 506 psi (1656 – 1150). Conclusion: The point that I would like to mention is that when you change your pump rate while performing well control operation. You must ensure that you do proper way to maintain bottom hole pressure. Otherwise, you may accidentally either decrease or increase the bottom hole pressure. If you accidentally decrease the bottom hole pressure, the influx will continue coming into a well and you will be in the big trouble. On the other hand, if you accidentally increase the bottom hole pressure, you may break wellbore and end up with lost circulation issue.

How are pressure and pit volume doing during the first circulation of the driller’s method? When we perform the first circulation of driller’s method, the casing pressure will increase due to gas expansion and the maximum casing pressure will be observed when the gas influx reaches surface. When gas is moved upward during circulation, the gas will expand due to pressure decrease (refer to Boyle’s gas law P1V1 = P2V2). The higher gas is moved up inside annulus, the higher expansion will be. Therefore, the system hydrostatic pressure will be decreased. For this reason, the casing pressure will increase in order to maintain constant bottom hole pressure. Let take a look at the equation Bottom hole pressure constant = Casing Pressure (increase to compensate for loss hydrostatic pressure) + Hydrostatic Pressure (decrease due to gas expansion). When the gas in the mud starts coming out on surface, the casing pressure will continually decrease. If the gas kick in the annulus is totally out of hole, casing pressure should be equal to Shut-In Drillpipe Pressure (SIDPP). Casing pressure sometimes may be slightly more than SIDPP due to safety factor that you add while circulating. In addition, pit volume will increase until gas reaches surface due to gas expansion. When gas reaches surface, the pit volume will start to decrease. The plot below demonstrates pressure profile of both casing pressure and tubing pressure during 1st circulation of driller’s method.

Establish Circulation in Driller’s Method The idea of holding casing pressure constant while bring up pumps is to maintain constant bottom hole pressure. Bring pump up to circulating rate, typically about 2-5 BPM, by holding constant casing pressure. The reason why we need to hold constant casing pressure is to maintain constant bottom hole pressure. Let’s me explain more by showing you some equations. BHP = Bottom Hole Pressure HP = Hydrostatic Pressure CP = Casing Pressure FrP = Frictional Pressure At static condition: BHP = HP in the annulus + CP At dynamic condition: BHP = HP in annulus + CP + FrP In the dynamic environment, if we pump as slowly as possible, FrP can be ignored. The equation above tells us that when you hold CP constant, the BHP will be maintained the same. After you bring pump to kill rate, you will get circulating pressure called Initial Circulating Pressure (ICP). ICP is summation of shut in drill pipe pressure (SIDPP) and pressure to overcome friction called Slow Circulating Rate Pressure (SCR pressure). Hence, we can write the relationship in term of equation below. ICP = SIDPP + SCR pressure

SCR pressure = ICP – SIDPP Note: Kill rate is normally about 2-5 BPM. Before performing this operation, you must ensure these following items; 1. Ensure that team members know their role and responsibility. You should have a pre job safety meeting before killing operation. 2. Eliminate all ignition sources that are close to the rig and vent lines of mud-gas separator. 3. Ensure that a circulating system is lined up properly. 4. Zero strokes counter and record time every activity.

Additional Topics EQUIVALENT CIRCULATING DENSITY (ECD) • While drilling, the mud passes through the drill string, comes out of bit nozzle, enters the annulus, travels up the annulus and comes out through flow line. • In this process when mud travels up in annulus, friction force acts downward. • The pressure equivalent to this friction force is called Annular Pressure Losses (APL). • Also, hydrostatic pressure acts downwards. • Thus, BHP = Hydrostatic Pressure + APL • (MW equivalent of Hyd Pr. + Mw Equivalent of APL) is termed as ECD. • Equivalent Circulating Density (ppg) =Static Mud Weight (ppg) + (Annular Pressure Loss)/ (TVD ×0.052)

Volumetric Well Control – When It Will Be Used Volumetric well control method is a special well control method which will be used when the normal circulation cannot be done. It is not a kill method but it the method to control bottom hole pressure and allow influx to migrate without causing any damage to the well. There are several situations where you cannot circulate the well as follows: • Pumps broken down • Plugged drill string/bit • Drill string above the kick • Drill string is out of the hole completely With the volumetric method, the volume of gas influx will allow migrating and casing pressure will increase till a certain figure then a specific amount of mud will bleed off to compensate the

increase in casing pressure. The volumetric method will allow the kick to surface while the bottom hole pressure is almost constant. Successful use of volumetric method requires personnel understand three basic concepts – 1. Boyle’s Law – Boyle’s law states that at constant temperature, the absolute pressure and the volume of a gas are inversely proportional in case of constant temperature within a closed system. The illustration below demonstrates volume and pressure as per Boyle’s Law.

In term of mathematical relationship, Boyle’s Law can be stated as P1 x V1 = P2 x V1 Where; P1 = pressure of gas at the first condition V1 = volume of gas at the first condition P2 = pressure of gas at the second condition V2 = volume of gas at the second condition 2. Hydrostatic pressure – Hydrostatic pressure is pressure created by column of fluid. Two factors affecting hydrostatic pressure are height of fluid and density of fluid. Pressure at the bottom hole equals to hydrostatic pressure plus surface pressure Pressure (bottom hole) = Hydrostatic Pressure + Surface Pressure We will apply this concept to see how the gas bubble will increase the bottom hole pressure. If the gas bubble is not allowed to expanded, the gas bubble in the well migrates up will act on the mud column below and increase bottom hole pressure. Increasing in the bottom hole pressure equates to hydrostatic pressure below the bubble. Bottom hole pressure = Gas bubble pressure + Hydrostatic pressure below the bubble

If we don’t want increase in bottom hole pressure, mud need to be bled off the well while the gas migrating up and the casing pressure must increase to compensate loss of hydrostatic pressure from bleed off. In the volumetric control, there are two ways to control bottom hole pressure while allowing the gas migrating up to surface. 1. Wait and let gas migrate. The migration of gas will increase bottom hole pressure and casing pressure. 2. Bleed off mud from the annulus. Mud that is bled off must be equal to the increase in bottom hole pressure. Both steps above must be carefully performed perform in a sequence. We will go to the detailed procedures in later post. 3. Relationship of height and fluid volume as determined by annular capacity – In order to determine volume of mud that equates to required hydrostatic pressure, we need to understand annulus capacity. It tells us how many bbl per foot in annulus and it can be calculated by this following formulas: Annular Capacity Factor (ACF) = (OD2-ID2) ÷ 1029.4 Where; ACF = Annular Capacity Factor in bbl/ft OD = Outside Diameter of Annular in inch ID = Inside Diameter of Annular in inch Once the ACF is known, we can determine Mud Increment (MI) which is the volume of mud bled off from the annulus to reduce the annular hydrostatic pressure by the amount of the pressure required. Mud Increment (MI) can be calculated by this following equation: Mud Increment (MI) = (PI x ACF) ÷ (0.052 x MW) PI = Pressure Increment in psi ACF = Annular Capacity Factor in bbl/ft MW = Mud Weight in the well in ppg

Gas Behavior and Bottom Hole Pressure in a Shut in well This is a classic example demonstrating how bottom hole pressure will be due to gas migration in a shut in well. This is very important concept in well control. Assumption: For this example, since the volume of the well does not change, and assuming that no mud or fluid is lost to the formation. This example will demonstrate the gas behavior in a shut in well. The well is shut-in without pipe in hole. 5 bbl of gas kick is taken and initial shut in casing pressure is equal to 400 psi. Hydrostatic head on top of gas is 4000 psi (see figure 1).

Fig-1

Fig-1

Even though the well is shut in, the gas influx is able to move upward due to gas migration. In this case, we will not allow any gas expansion and let the gas gradually migrate. The well is shut in and gas is allowed to migrate up hole until hydrostatic pressure underneath gas is 2000 psi (see the figure 2). What will happen to bottom hole pressure and casing pressure?

With Bolye’s Law concept, we will apply it see how much gas bubble should be. According to this example, Pressure of gas (P1) is 4400 which equates to the bottom hole pressure. Volume of gas at beginning (V1) is 5 bbl P1 x V1 = P2 x V2

4400 x 5 = P2 x 5 P2 = 4400 psi ->Gas pressure remains constant. You have total of hydrostatic pressure of 4,000 psi at the beginning. Currently, you have 2000 psi of hydrostatic at the bottom therefore you have 2000 psi of hydrostatic on top of gas. See the figure 3.

Fig-3

Fig-4

Let’s see how much casing pressure will be. Apply hydrostatic pressure concept to solve this problem. Gas influx pressure = hydrostatic pressure above the gas influx + casing pressure 4400 = 2000 + casing pressure Casing pressure = 2400 psi Moreover, you can find the bottom hole pressure by applying the same concept. Bottom hole pressure = hydrostatic pressure of mud + casing pressure Bottom hole pressure = 4,000 + 2,400 Bottom hole pressure = 6,400 psi. (See Fig-4) Conclusion: If the well is shut in and the gas influx is allowed to migrate, gas pressure will remain constant; however, bottom hole pressure and casing pressure will increase. If you let casing pressure (surface pressure) increase too much, you can break formation or damage surface equipment.

DAY-2 --------------- Session - II Well Kill Using Wait and Weight Method (Balanced Method) The “Wait and Weight” method is the method recommended, in some circumstances, for controlling an influx taken while drilling or circulating on bottom. When drillpipe (string) volume is greater than open hole volume, the influx will already be inside the casing before heavy mud reaches the open hole. In this case the “Driller’s Method” can be a better solution as the danger of gas expansion is removed immediately while weighing up mud can take hours. Advantages of “Wait and Weight” method The annular pressure will usually be lower and the chance of formation breakdown is therefore reduced. The hole and the wellhead equipment are subjected to high pressures for the shortest possible time since the influx is circulated out and the well is killed in one circulation. Disadvantages of “Wait and Weight” method Considerable waiting time while weighing up mud can cause gas migration If large increases in mud weight is required, this may be possible in stages only This method involves one circulation. Kill mud is prepared and is pumped from surface to bit while following a prepared drillpipe pressure drop schedule. Once the kill mud enters the annulus, a constant drillpipe pressure is maintained until the heavy mud returns to surface. Procedure The procedure for the Wait and Weight method is as follows: After the well has been secured and pressures have stabilised, complete kill sheet including kill graph Bring pumps up to speed keeping casing pressure constant by manipulating the choke When pump is up to kill speed the choke is manipulated to keep the drill pipe pressure at initial circulating pressure (ICP). Pump kill mud down drill pipe keeping casing pressure constant and allowing drill pipe pressure to fall from ICP to final circulating pressure (FCP). When kill mud reaches the bit the drill pipe pressure should be at FCP. Continue pumping kill mud keeping drill pipe pressure constant at FCP until the kick is circulated out and kill mud reaches surface.

Equations KMW = (SIDPP / (0.052 * TVD)) + OMW Trip margin may not be included in the calculation for kill mud weight. The major reason for this is to avoid any unnecessary additional wellbore pressure that could result in formation breakdown. Calculate initial circulating pressure: ICP = SCRP + SIDPP (psi) Calculate Final circulating pressure: FCP = (

𝐾𝑀𝑊 𝑂𝑀𝑊

) ∗ 𝑆𝐶𝑅𝑃(𝑝𝑠𝑖)

Calculate surface to bit strokes: Strokes = Drillstring volume (bbls) Pump output (bbls/stroke) Calculate time to pump surface to bit: Time (mins) = Total strokes from surface to bit) Strokes per minute Where: 

KMW = Kill mud weight (ppg)



SIDPP = Shut in Drillpipe pressure (psi)



TVD = True vertical depth (ft)



OMW = Original Mud Weight (ppg)



ICP = Initial circulating pressure (psi)



SCRP = slow circulating rate pressure (psi)



FCP = Final circulating pressure (psi)

Wait and Weight Well Control Method (Engineer’s Method) Wait and Weight Well Control Method or someone calls Engineer’s Method is a method to control well with one circulation. Kill weight mud is displaced into drill string and kick (wellbore influx) is removed while displacing a wellbore. Steps of the weight and weight method for well control are as follow: 1. Shut in the well.

2. Allow pressure to stabilize and record stabilized shut in casing pressure, initial shut in drill pipe pressure, and pit gain. If you have a float in the drill string, you must bump the float in order to see the shut-in drill pipe pressure 3. Perform well control calculations and following items must be figured out.  Bottomhole pressure based on drill pipe pressure.  Kill Mud weight necessary to balance the kick  Drillpipe pressure schedule  Maximum surface casing pressure during well control operation.  Maximum pit gain during 4. Raise mud weight in the system to required kill mud weight. 5. Establish circulation to required kill rate by holding casing pressure constant. 6. Follow drill pipe schedule until kill weight mud to the bit. 7. Hold drill pipe pressure constant once kill weight mud out of the bit until complete circulation. 8. Check mud weight out and ensure that mud weight out is equal to kill mud weight. 9. Shut down and flow check to confirm if a well is static. 10. Circulate and condition mud if required.

Maximum pit gain from gas kick in water based mud In water based mud, you can not only estimate the maximum surface casing pressure, but you are also be able to determine the maximum pit gain due to gas influx. The following formula demonstrates how to figure out the maximum pit gain from gas influx in water based mud system.

Maximum Pit Gain in bbl P is formation pressure in psi. V is original pit gain in bbl. C is annular capacity in bbl/ft. Kill Weight Mud in ppg Let’s take a look at this following example in order to get more understanding regarding this topic. Drill well with water based mud. Pit gain = 20 bbl

Initial shut in casing pressure = 600 psi

Initial shut in drill pipe pressure = 500 psi

Current mud weight = 12.5 ppg

Hole depth = 6,000’MD/4,800’TVD

Hole diameter = 12-1/4 inch

Drill pipe = 5 inch According to the data, you need to figure out the Kill Mud Weight, formation pressure, and annular capacity. Kill Weight Mud = current mud weight + (shut in drill pipe pressure ÷ (0.052 x TVD)) Kill Weight Mud = 12.5 + (500 ÷ (0.052 x 4800)) = 14.5 ppg Formation pressure = surface pressure + hydrostatic pressure Formation pressure = 500 + (0.052 x 12.5 x 4800) = 3620 psi Determine annular capacity: Annular capacity = (12.252 – 52) ÷ 1029.4 = 0.1215 bbl/ft Once you get all parameters required, you can add all of them into the equation like this.

Maximum Pit Gain = 98.5 bbl

Maximum Surface Pressure from Gas Influx in Water Based Mud When a well is shut in due to well control operation, the casing pressure will increase due to gas migration and gas expansion. In water based mud, you are able to estimate the maximum surface pressure with this following formula.

Max surface pressure in psi. P is expected formation pressure in psi. V is pit volume gain in bbl. KWM is kill weight mud in ppg. An is an annular capacity in bbl/ft. We can easily estimate surface pressure in water based mud because gas kick is not soluble in water based mud. On the other hand, with oil based mud, you will not be able to use this equation because you will not see the real volume of gas kick due to gas solubility in oil. Determine the maximum surface pressure. Drill well with water based mud. Pit gain = 25 bbl

Stabilized casing pressure = 600 psi

Initial drill pipe pressure = 450 psi

Current mud weight = 12.0 ppg

Hole depth = 10,000’MD/9,500’TVD

Hole diameter = 8.5 inch

Drill pipe = 5 inch Determine kill weight mud with this equation: KMW = current mud weight + (drill pipe pressure ÷ (0.052 x Hole TVD)). KMW = 12.0 + (450 ÷ (0.052 x 9500)) = 12.91 You need to round the kill weight mud up; therefore, KMW is 13.0 ppg. Determine formation pressure. Formation pressure = surface pressure + hydrostatic pressure Formation pressure = 450 + (0.052 x 12.0 x 9500) = 6378 psi Determine annular capacity: Annular capacity = (8.52 – 52) ÷ 1029.4 = 0.0459 bbl/ft Once you get all parameters you need, you can determine a figure.

Maximum surface pressure = 1344 psi.

Formation Pressure from Kick Analysis Once you shut in the well in and obtain shut in drill pipe pressure, you can estimate formation pressure by applying the hydrostatic pressure concept. This following equation demonstrates you how to figure out formation pressure from the kick analysis. Formation Pressure = SIDDP + (0.052 x Hole TVD x Current Mud Weight)

Formation Pressure from Kick Analysis Formation Pressure in psi

SIDDP (shut in drill pipe pressure) in psi

Hole TVD (true vertical depth) in ft

Current Mud Weight in ppg

Example: Well depth = 8,500′MD/8,000 TVD. SIDPP = 300 psi Current mud weight = 10.0 ppg What is the formation pressure in psi? Formation Pressure = 300+ (0.052 x 8000 x 10.0) Formation pressure = 4,460 psi

Drill Pipe Pressure Schedule Calculation for Wait and Weight Well Control Method Current mud weight = 9.5 ppg

Pump output = 0.1 bbl/stroke

Well depth = 9000’MD/9000’TVD

Drill string capacity = 0.0178 bbl/ft

Surface line volume = 15 bbl.

Shut in casing pressure = 700 psi

Shut in drill pipe pressure = 500 psi

ICP = 1600 psi at 30 spm as kill rate

Please follow steps below to determine the drill pipe pressure schedule (step down chart).

Determine kill weight mud KWM = OMW + [SIDPP ÷ (0.052 x TVD)] Where; KWM is kill weight mud in ppg.

OMW is original mud weight in ppg.

SIDPP is shut in drill pipe pressure in psi.

TVD is true vertical depth of the well in ft.

KWM = 9.5+ [500 ÷ (0.052 x 9000)] KMW = 10.6 ppg Determine Slow Circulating Rate (SCR) SCR = ICP – SIDPP SCR is slow circulating rate in psi.

ICP is initial circulating pressure in psi.

SIDPP is shut in drill pipe pressure in psi.

SCR = 1600 – 500 = 1100 psi

Determine Final Circulating Pressure (FCP) FCP = SCR x KWM ÷ OMW FCP is final circulating pressure in psi.

SCR is slow circulating rate in psi.

KWM is kill weight mud in ppg.

OMW is original mud weight in ppg.

FCP = 1100 x 10.6 ÷ 9.5 = 1227 psi Determine stroke from surface to bit Drill string volume = Drill pipe capacity x TD ÷ Pump output Drill sting volume is in strokes.

Drill pipe capacity is in bbl/ft.

TD is well measured depth in ft.

Pump output in bbl/stroke.

Drill string volume = 0.0178 x 9000 ÷ 0.1 = 1602 strokes According to this example, you need 1602 stokes in order to bring kill mud to the bit and drill pipe pressure will change from 1600 psi (ICP) to 1227 psi (FCP) within 1602 strokes. Hence pressure drop per stoke is (ICP – FCP) ÷ surface to bit (1600 – 1227) ÷ 1602 = 0.2328 psi/stroke This figure (0.2328 psi/stroke) is very small and difficult to make adjustment with equipment on the rig. Therefore, you need to know how much pressure drop per required strokes. For this example, I will determine pressure drop per 200 strokes. Drill pipe pressure drop = 0.2328 x 200 = 47 psi Then we need to create a table showing pressure schedule. For the first line, you need 150 stokes to bring KWM to the rotary table then drill pipe pressure will be dropped approximately 47psi/200 strokes until it reach 1227 which is the final circulating pressure. The step down table look like this. Strokes

Drill Pipe Pressure (psi)

Remarks

150

1600

You need to pump 150 stokes in order tobring kill from mud pump to rotary table

350

1554

DP drops 47 psi/200 strokes.

550

1506

DP drops 47 psi/200 strokes.

750

1459

DP drops 47 psi/200 strokes.

950

1412

DP drops 47 psi/200 strokes.

1150

1365

DP drops 47 psi/200 strokes.

1350

1318

DP drops 47 psi/200 strokes.

1550

1271

DP drops 47 psi/200 strokes.

1750

1227

Final circulating pressure

Pressure Profile of Drillpipe and Casing Pressure while killing a well with wait and weight method Firstly, we will take a look at the drillpipe pressure. When kill weight mud is displaced in the well, drill pipe pressure drops as per the drill pipe schedule. Once kill weight mud is to the bit, drill pipe pressure is maintained until the well is killed. A pressure profile will look like the following chart.

Casing Pressure Secondly, we will take a look at the casing pressure. The casing pressure will increase because gas expansion while it is being circulated. The maximum casing pressure occurs when gas reaches at surface. Then casing pressure will drop rapidly because gas is coming out on surface. Once gas is totally removed from the surface, there is still some casing pressure due to original mud weight. The casing pressure will gradually decrease and drop to 0 psi which means the well

is killed with the kill weight mud. A pressure profile demonstrates how casing pressure acts while circulating.

Volumetric Well Control Volumetric well control method is a special well control method which will be used when the normal circulation cannot be done. It is not a kill method but it the method to control bottom hole pressure and allow influx to migrate without causing any damage to the well. There are several situations where you cannot circulate the well as follows: • Pumps broken down • Plugged drill string/bit • Drill string above the kick • Drill string is out of the hole completely With the volumetric method, the volume of gas influx will allow migrating and casing pressure will increase till a certain figure then a specific amount of mud will bleed off to compensate the increase in casing pressure. The volumetric method will allow the kick to surface while the bottom hole pressure is almost constant. Successful use of volumetric method requires personnel understand three basic concepts – 1. Boyle’s Law – Boyle’s law states that at constant temperature, the absolute pressure and the volume of a gas are inversely proportional in case of constant temperature within a closed system. The illustration below demonstrates volume and pressure as per Boyle’s Law. In term of mathematical relationship, Boyle’s Law can be stated as P1 x V1 = P2 x V1 P1 = pressure of gas at the first condition V1 = volume of gas at the first condition P2 = pressure of gas at the second condition V2 = volume of gas at the second condition 2. Hydrostatic pressure – Hydrostatic pressure is pressure created by column of fluid. Two factors affecting hydrostatic pressure are height of fluid and density of fluid.

Pressure at the bottom hole equals to hydrostatic pressure plus surface pressure Pressure (bottom hole) = Hydrostatic Pressure + Surface Pressure We will apply this concept to see how the gas bubble will increase the bottom hole pressure. If the gas bubble is not allowed to expanded, the gas bubble in the well migrates up will act on the mud column below and increase bottom hole pressure. Increasing in the bottom hole pressure equates to hydrostatic pressure below the bubble. Bottom hole pressure = Gas bubble pressure + Hydrostatic pressure below the bubble

If we don’t want increase in bottom hole pressure, mud need to be bled off the well while the gas migrating up and the casing pressure must increase to compensate loss of hydrostatic pressure from bleed off. In the volumetric control, there are two ways to control bottom hole pressure while allowing the gas migrating up to surface. 1. Wait and let gas migrate. The migration of gas will increase bottom hole pressure and casing pressure. 2. Bleed off mud from the annulus. Mud that is bled off must be equal to the increase in bottom hole pressure. Both steps above must be carefully performed perform in a sequence. We will go to the detailed procedures in later post. 3. Relationship of height and fluid volume as determined by annular capacity – In order to determine volume of mud that equates to required hydrostatic pressure, we need to understand annulus capacity. It tells us how many bbl per foot in annulus and it can be calculated by this following formulas: Annular Capacity Factor (ACF) = (OD2-ID2) ÷ 1029.4 ACF = Annular Capacity Factor in bbl/ft ID = Inside Diameter of Annular in inch

OD = Outside Diameter of Annular in inch

Once the ACF is known, we can determine Mud Increment (MI) which is the volume of mud bled off from the annulus to reduce the annular hydrostatic pressure by the amount of the pressure required. Mud Increment (MI) can be calculated by this following equation: Mud Increment (MI) = (PI x ACF) ÷ (0.052 x MW) PI = Pressure Increment in psi ACF = Annular Capacity Factor in bbl/ft MW = Mud Weight in the well in ppg

Lubrication or top kill This method of lubricating gas out of a well is more accurate than the standard lubricating procedure if the well is taking fluid. Comparing the actual and modeled pressures helps quickly spot common sources of error that complicate standard lubrication procedures. There are two common lubrication procedures: 

Pumping a kill fluid, waiting, and bleeding off pressure



Continued circulation across the top of the well (the dynamic lubrication procedure).

The pump, wait, and bleed method is most commonly used and may require numerous cycles to remove the gas completely. Both methods involve the coordinated use of a pump, a choke, and an accurate measuring tank. CONVENTIONAL LUBRICATION The pump, wait, and bleed lubrication procedure involves the following steps: 

Pump fluid into a closed-in well (the surface pressure increases because of fluid compression).  Allow sufficient time for the fluid to lubricate (fall or slip through the column of gas).  Determine the hydrostatic pressure of the fluid volume lubricated for the particular cycle. The following formulas can be used to determine the hydrostatic pressure increase after each lubrication cycle: Hydrostatic increase = (hydrostatic head per barrel of lubricating fluid) x (volume lubricated per cycle). Hydrostatic head per barrel of lubricating fluid = (fluid -gradient)/(capacity). The capacity is the linear volume in bbl/ft of the annulus, tubing, or casing, depending on the location of the gas.  Bleed gas through the choke to reduce bottom-hole pressure by the increase from the compression of the gas and the hydrostatic increase from the lubricating fluid. The use of this procedure can be tiresome and requires complicated calculations that sometimes prove difficult for field use. The bottom-hole pressure before and after each cycle should be nearly the same. Several sources of error, however, may contribute to differences in bottom hole pressures:



The volume measurements are inaccurate because of measuring tank design (excessive surface area), gas-cut fluids bled off, and insufficient time for fluid to lubricate through the gas.  The well bore is accepting fluids. For example, the fluid can enter open perforations in completed wells, or the fluid can be squeezed into weak zones or below the casing shoe in open well bores.  The calculations are field dependent. NEW PROCEDURE For a gas well, one of the first decisions is whether to bullhead or lubricate for the kill. Fig. 1 is a general schematic of a well type that was often bullheaded dead by the operator. These wells often required several tubing volumes for the kill operation. Because the bullheading operation was thought to damage the formation, a lubrication procedure was later used. The sources of error with the standard lubrication procedure made the process difficult, and excessive amounts of completion brine were still lost to the formation. The lubrication procedure can be easier and more accurate to use if the following three pressures are properly accounted for during each lubrication cycle: the initial pressure prior to lubrication (P1), the compression pressure increase from pumping in the lubricating fluid (P2), and the final pressure reached after the gas is vented (P3). Given the following assumptions, Equations 1 and 2 define the lubricating pressure relationships: 

The product of the pressure times the volume of gas remains constant (P1V1 P2V2).  The lubricating fluid density, once the gas has been displaced, will balance (or overbalance) the formation pressure.  Only gas is bled from the well. Equation 1 is for vertical or constant-drift directional wells, and Equation 2 is for deviated wells. The simplicity of Equation 1 makes it well-suited to most lubrication applications. Most often, lubrication is required to remove a vertical column of gas.

Stripping (using Annular Preventer) The act of putting drillpipe into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well. This is necessary when a kick is taken, since well kill operations should always be conducted with the drillstring on bottom, and not somewhere up the wellbore. If only the annular BOP has been closed, the drillpipe may be slowly and carefully lowered into the wellbore, and the BOP itself will open slightly to permit the larger diameter tool joints to pass through. If the well has been closed with the use of ram BOPs, the tool joints will not pass by the closed ram element. Hence, while keeping the well closed with either another ram or the annular BOP, the ram must be opened manually, then the pipe lowered until the tool joint is just below the ram, and then the ram closed again. This procedure is repeated whenever a tool joint must pass by a ram BOP. Rig crews are usually required to practice ram-to-ram and ram-to-annular stripping operations as part of their well control certifications. In stripping operations, the combination of the pressure in the well and the weight of the drillstring is such

that the pipe falls in the hole under its own weight, whereas in snubbing operations the pipe must be pushed into the hole.

Snubbing The act of putting drillpipe into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well. Snubbing is necessary when a kick is taken, since well kill operations should always be conducted with the drillstring on bottom, and not somewhere up the wellbore. If only the annular BOP has been closed, the drillpipe may be slowly and carefully lowered into the wellbore, and the BOP itself will open slightly to permit the larger diameter tool joints to pass through. If the well has been closed with the use of ram BOPs, the tool joints will not pass by the closed ram element. Hence, while keeping the well closed with either another ram BOP or the annular BOP, the ram must be opened manually, then the pipe lowered until the tool joint is just below the ram, and then closing the ram again. This procedure is repeated whenever a tool joint must pass by a ram BOP. In snubbing operations, the pressure in the wellbore acting on the cross-sectional area of the tubular can exert sufficient force to overcome the weight of the drillstring, so the string must be pushed (or "snubbed") back into the wellbore. In ordinary stripping operations, the pipe falls into the wellbore under its own weight, and no additional downward force or pushing is required.

Recommended stripping guidelines

Stripping using ram preventer A ram-type blowout preventer used to provide primary pressure control in high-pressure snubbing operations. Stripping rams are used when the wellhead pressure is higher than the limitations of a stripper bowl. Stripping with an Annular BOP Drill pipe can be rotated and tool joints stripped through a closed packer, while maintaining a full seal on the drill pipe. Longest packer life is obtained by adjusting the closing chamber pressure just low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes through the packer. The leakage indicates the lowest usable closing pressure for minimum packer wear and provides lubrication for the drill pipe motion through the packer. A pressure regulator valve should be set to maintain the proper closing pressure. For stripping purposes, the regulator valve is usually too small and cannot respond fast enough for effective control, so a surge bottle is connected as closely as possible to the BOP closing port (particularly for subsea installations). The surge bottle is precharged with nitrogen, and is installed in the BOP closing line in order to reduce the pressure surge which occurs each time a tool joint enters the closed packer during stripping. A properly installed surge bottle helps reduce packer wear when stripping. Check manufacturer’s recommendations for proper nitrogen precharge pressure for your particular operating requirements. In subsea operations, it is advisable to add an accumulator to the opening chamber line to prevent undesirable pressure variations. Ram type BOP A ram-type blowout preventer is basically a large bore valve (see Figure 1B). The ram blowout preventer is designed to seal off the well bore when pipe, casing, or tubing is in the well. In a BOP stack, ram preventers are located between the annular BOP and the wellhead (see Figure 2B). There are typically 3 or 4 ram preventers in a BOP stack. Flanged or hubbed side outlets are located on one or both sides of the ram BOPs. These outlets are sometimes used to attach the valved choke and kill lines to. The outlets enter the wellbore of the ram preventer immediately under the ram cavity.

Figure 1A

Figure 1B

Figure 2

Figure 3

Other than sealing off the well bore, rams can be used to hang-off the drill string. A pipe ram, closed around the drill pipe with the tool-joint resting on the top of the ram, can hold up to 600,000 lbs. of drill string.

How wait and weight method controls bottom hole pressure There are 2 steps that must be took into consideration separately. The first one is when kill weight mud is displaced to the bit and the second one is when the kill weight mud from bit to surface. 1) Displace kill weight mud to the bit Once kill weight mud is mixed and displaced into drill pipe, drill pipe pressure will be decreased due to increasing in hydrostatic pressure. In order to control bottom hole pressure, a drill pipe pressure schedule must be developed and followed until kill mud weight to the bit.

Take a look at the equation: Pressure in drillpipe side = BHP = Pressure in casing side DPP + HP – Frictional P in drillstring = BHP = HP + CP + Frictional P in annulus

DPP is drill pipe pressure.

HP is hydrostatic pressure.

Frictional P is frictional pressure.

CP is casing pressure.

At drillpipe side: DPP will drop when kill mud weight is displaced. HP will increase due to kill mud weight in the drillstring. Friction P in drillstring will not change so much. At casing side: HP will decrease due to gas expansion in the annulus. CP will increase in order to compensate hydrostatic pressure loss. Frictional P in annulus had minimal effect on bottom hole pressure due to slow flow rate while killing the well. 2) Displace kill weight mud from bit to surface Once the kill weight mud comes out of the bit, there is one single column of hydrostatic in the drillstring. Therefore, in order to maintain bottom hole pressure constant, drill pipe pressure must be maintained while displacing.

Conclusion: • Use the drill pipe pressure schedule to control constant bottom hole pressure while displacing kill weight mud to the bit. • After kill mud out of the bit, maintain drill pipe pressure until circulation complete.

Additional Topics Well kill A well kill is the operation of placing a column of heavy fluid into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface. It works on the principle that the hydrostatic head of the "kill fluid" or "kill mud" will be enough to suppress the pressure of the formation fluids. Well kills may be planned in the case of advanced interventions such as workover, or be contingency operations. The situation calling for a well kill will dictate the method taken. Methods of well kill Reverse circulation Forward circulation

Bullheading Lubricate and bleed

Well Shut-in An oil or gas well that is closed off; the well is shut so that it does not produce a fluid product of any kind. When one or more warning signs of kicks are observed, steps should be taken to shut in the well. If there is any doubt that the well is flowing, shut it in and check the pressures. It is important to remember that there is no difference between a small-flow well and a full-flowing well, because both can very quickly turn into a big blowout. Drilling—land or bottom-supported offshore rig When a primary kick warning sign has been observed, do the following immediately: 1. Raise the Kelly until a tool joint is above the rotary table. 2. Stop the mud pumps. 3. Close the annular preventer. 4. Notify company personnel. 5. Read and record the shut-in drillpipe pressure, the shut-in casing pressure, and the pit gain. Raising the Kelly is an important procedure. With the Kelly out of the hole, the valve at the bottom of the Kelly can be closed if necessary. Also, the annular-preventer members can attain a more secure seal on the pipe than a Kelly. Tripping—land or bottom-supported offshore rig A high percentage of well-control problems occur when a trip is being made. The kick problems may be compounded when the rig crew is preoccupied with the trip mechanics and fails to observe the initial warning signs of the kick.

Shut-in procedures When a primary warning sign of a kick has been observed, do the following immediately: 1. Set the top tool joint on the slips. 2. Install and make up a full-opening, fully opened safety valve on the drillpipe. 3. Close the safety valve and the annular preventer. 4. Notify company personnel. 5. Pick up and make up the Kelly. 6. Open the safety valve. 7. Read and record the shut-in drillpipe pressure, shut-in casing pressure, and pit gain. Installing a fully opened, full-opening safety valve in preference to an inside blowout preventer (BOP), or float, valve is a prime consideration because of the advantages offered by the fullopening valve. If flow is encountered up the drillpipe as a result of a trip kick, the fully opened, full-opening valve is physically easier to stab. Also, a float-type inside-BOP valve would automatically close when the upward-moving fluid contacts the valve. If wireline work, such as drillpipe perforating or logging, becomes necessary, the full-opening valve will accept logging tools approximately equal to its inside diameter, whereas the float valve may prohibit wireline work altogether. After the kick is shut in, an inside-BOP float valve may be stabbed on the full-opening valve to allow stripping operations.

Pump Output Calculation for Duplex Pump and Triplex Pump Rig pump output, normally in bbl per stroke, of mud pumps on the rig is important figures that we really need to know because we will use pump output figures to calculates many things such as bottom up strokes, wash out depth, tracking drilling fluid, etc. In this post, you will learn how to calculate pump output for triplex pump and duplex pump.

Triplex Pump Output Formula Triplex Pump Output in bbl/stk = 0.000243 x (liner diameter in inch) 2 X (stroke length in inch) Example: Determine the pump output in bbl/stk at 100% and 97% efficiency Linner size = 6 inch Stroke length = 12 inch

Triplex pump output: PO @ 100% = 0.104976 bbl/stk

PO @ 100% = 0.000243 x 62 x 12

Adjust the triplex pump output for 97% efficiency: Decimal equivalent = 97 ÷ 100 = 0.97 PO @ 97% = 0.104976 bbl/stk x 0.97 PO @ 97% = 0.101827 bbl/stk Duplex Pump Output Formula Duplex Pump Output in bbl/stk = 0.000162 x S x [2(D)2 - d2] D = liner diameter in inch d = rod diameter in inch

S = stroke length in inch

Example: Determine the duplex pump output in bbl/stk at 100% and 85% efficiency Liner diameter = 6 inch Rod diameter = 2.0 in. PO @ 100% = 0.000162 x 12 x [2 (6) 2 -22 ]

Stroke length = 12 inch Duplex pump efficiency = 100 %. PO @ 100% = 0.13219 bbl/stk

Adjust pump output for 85% efficiency: PO @ 85% = 0.132192 bbl/stk x 0.85 PO @ 85% = 0.11236 bbl/stk

Calculate inner capacity of open hole/inside cylindrical objects There are several formulas to calculate inner capacity depending on unit of inner capacity required. Please read and understand the formulas below: Formula#1) Calculate inner capacity in bbl/ft Inner Capacity in bbl/ft = (ID in.)2 ÷1029.4 Example: Determine inner capacity in bbl/ft of a 6-1/8 in. hole: Inner Capacity in bbl/ft = 6.1252÷1029.4 Inner Capacity in bbl/ft = 0. 0364 bbl/ft Formula#2) Calculate inner capacity in ft/bbl Example: Determine inner capacity in ft/bbl of 6-1/8 in. hole: Inner Capacity in ft/bbl = 1029.4 ÷ 6.1252 Inner Capacity in = 27.439 ft/bbl Inner Capacity in ft/bbl = 1029.4 ÷ (ID in.) Formula#3) Calculate inner capacity in gal/ft Inner Capacity in gal/ft = (ID in.)2 ÷24.51 Example: Determine inner capacity in gal/ft of 6-1/8 in. hole: Inner Capacity in gal/ft = 6.1252÷ 24.51 Inner Capacity in = 1.53 gal/ft

Formula#4) Calculate inner capacity in ft/gal Inner Capacity in ft/gal = 24.51 ÷ (ID in.)2 Example: Determine inner capacity in ft/gal of 6-1/8 in. hole: Inner Capacity in ft/gal = 24.51 ÷ 6.1252 Inner Capacity in ft/gal = 0.6533 ft/gal Determine the volume of mud to fill up the inner of the cylindrical objects by the following equation. Inner Volume = Inner Capacity x Length Example: Inner capacity = 0. 0364 bbl/ft Volume = 0. 0364 x 3,000 = 109.2 bbl.

Length = 3000 ft

DAY-2 --------------- Session - III Unusual situations in well control Some of the common unusual situations encountered: a. Drill pipe plugged during killing operation b. No pipe in hole c. Hole in drill string or drill string parting d. Lost circulation e. Excessive casing pressure e. Plugged and stuck off-bottom etc. Plugged or washed bit nozzles When plugged nozzles occur whilst pumping at a constant pump rate, Standpipe pressure (Pst) will increase. If, after opening the choke further, Pst remains higher than expected and choke pressure (Pchoke) drops, the nozzles may be partially plugged, or there is a restriction in the annulus. Newly adjusted standpipe pressures will have to be used during further well killing operations. (Always check if the valves upstream of the Pchoke measuring point are fully open). The Pst graph needs to be revised according to the procedure used for changing the circulating rate regardless if any change in circulating rate has taken place. Always keep in mind that nozzles can "un-plug" again after a while, and graphs should be re-adjusted accordingly. If circulation cannot re-establish by increasing the pump pressure, a wireline operation could be planned to try to open the bit with a string shot or perforate as far down the string as possible. While rigging up to perforate, observe SICP for gas migration. If gas migration is suspected consider using the volumetric well kill technique. Partial plugging Total plugging

Washed out bit nozzles Plugged Chokes Cuttings, loose formation particles, etc., may plug the choke and cause a sudden rise in pressure in the annulus and drillpipe. If this happens, another choke must be opened, or pumping must be stopped immediately to avoid over-pressuring the well. In order to take prompt action and to ensure that the correct operational steps are made, it is essential that:  

There is good communication between all persons involved at all stages of the well control operation The actual pressures on drillpipe and annulus are always known.

If the chokes become partially plugged and the decision is made not to interrupt the operation for cleaning the chokes, it may be necessary to reduce the pumping speed, because of too high standpipe pressures.

Change in Circulating Kill Rate During well killing operations the circulating rate may have to be reduced because of higher than preferred pumping pressures or pumping speed may have to be increased if faster pumping is desired. The procedure to change the circulating rate and to determine the new circulating pressure while circulating out the kick.

Complete Power Failure during the Well Kill The provision of a power supply or emergency generator system linked with the accumulator system to maintain pressure on the BOP accumulator unit, in case of a complete power failure during well control operations. Shall be available on each rig.

Choke Washout When the well is being killed using the Driller's method or the ‘Wait and Weight’ method inability to maintain casing pressure indicates choke washout. If an abnormal decrease of drillpipe pressure and casing pressure is noticed it is possible that a washed out choke is the cause. If a washed choke is suspected the well should be shut-in. The secondary circuit using the spare adjustable choke will be prepared. Well control procedures will be re-established using the spare adjustable choke. Immediate repair action on the washed-out choke should be considered.

Depth of Washout Washout in drill string can cause big problem later such as parted drill string. When we see stand pipe pressure decrease without changing any parameters as flow rate, mud properties, etc, you may need to consider following items before you decide to pull out of hole for washout. 1. Check surface line: You may need to close stand pipe valves or IBOP and then pressure up to see leaking in the surface. If you see pressure drop, you can fix the surface problem. Anyway you still need to test system again. 2. Check drillstring: You may pump the same flow rate and see how your MWD tool down hole response. If y MWD tool response gets weaker signal so it means that you have washout somewhere above MWD tool. If not, you may have washout below that such as bit, mud motor, etc. Method 1: The concept of this method is to pump plugging material to plug the wash out. We will count how many strokes pump till pump pressure increases then we can calculate back where the washout is by applying internal capacity concept and pump output concept.

Depth of washout in ft= (strokes pumped till seeing pressure increase x pump output in bbl/stk) ÷ drill pipe capacity in bbl/ft Determine washout depth from following information: Internal drill pipe capacity = 0.00742 bbl/ft Pump output = 0.0855 bbl/stk Pressure increase was noticed after 400 strokes. Depth of washout, ft = 400 stk x 0.0855 bbl/stk ÷ 0.00742 bbl/ft Depth of washout = 4609 ft Method 2: The concept of this method is to pump material that can be easily observed from drill pipe pass through wash out into annulus and over the surface. We can calculate the depth of washout bases on the combination volume of internal drill pipe volume and annulus volume. Note: The materials can be easily observed when it comes across the shakers are as follows: carbide, corn starch, glass beads, bright colored paint, etc. Depth of washout in ft = (strokes pumped till observed material on surface x pump output in bbl/stk) ÷ (drill pipe capacity in bbl/ft + annular capacity in bbl/ft) Determine depth of washout from following information: Internal drill pipe capacity = 0.00742 bbl/ft Pump output = 0.0855 bbl/stk Annulus capacity = 0.0455 bbl/ft The material pumped down the drill pipe was noticed coming over the shaker after 2500 strokes. Depth of washout, ft = (2500 x 0.0855) ÷ (0.00742+0.0455)

Depth of washout = 4039 ft

If you want to subtract volume from bell nipple to shale shaker, you can subtract the volume out of total volume pumped. Therefore the formula will be Depth of washout, ft = (strokes pumped till observed material on surface x pump output in bbl/stk – volume (bbl) from bell nipple to shale shaker) ÷ (drill pipe capacity in bbl/ft + annular capacity in bbl/ft) Example: Internal drill pipe capacity = 0.00742 bbl/ft Pump output = 0.0855 bbl/stk

Annulus capacity = 0.0455 bbl/ft

The material pumped down the drill pipe was noticed coming over the shaker after 2500 strokes. Volume from bell nipple to shale shaker = 10 bbl Depth of washout in ft = (2500 x 0.0855 – 10) ÷ (0.00742+0.0455) Depth of washout = 3850 ft ANYWAY PLEASE REMEMBER. If you know that your wash out is down hole, practically, we need to pull out of hole ASAP after we determine washout situation. The more you pump, more washout will be occurred.

Unusual Well-Control Operations (Practical Well Control by Ron Baker) During a well-control operation, the characteristics of the well or kick may call for procedures that deviate from normal. Rig supervisors and crews should be aware of such procedures and be prepared to initiate them if necessary. While it is impossible to cover every unusual situation that could occur, this chapter covers several. A hole in the drill string (Washed out) When a kick is being circulated out of the well and a hole is washed through the drill string, a decrease in SIDPP occurs without a corresponding decrease in SICP. Because SIDPP decreases, the choke operator may close the choke in an attempt to bring SIDPP back to the previous value. Closing the choke, however, causes casing pressure to increase to a value higher than that required to prevent the entry of additional kick fluids into the well. If the hole in the pipe is large, the choke may be closed to the point that the additional back-pressure causes formation fracture and lost circulation. Therefore, it is important to be alert to the possibility of a hole’s being washed through the pipe and to be able to react properly to the problem. Once it is certain that a hole has appeared in the string, the next step is to determine whether the hole is above or below the kick fluids, because the location of the hole bears on how the situation should be handled. For example, if the hole in the pipe is above the kick, it becomes difficult or impossible to maintain constant bottomhole pressure while circulating the kick in the conventional manner. Since the hole opens the pipe to annular pressure, drill pipe pressure gauge readings may help to locate the hole. For example, if SIDPP is much higher than expected and does not decrease when a small amount of mud is bled from the well, it is likely that the hole in the pipe is above the kick. In fact, if no kill-weight mud is in the drill pipe, SIDPP may be the same as SICP. If, on the other hand, the hole in the pipe is below the kick, it is likely that SIDPP will be near the previous shut-in value. Since a slower-than-normal pump speed is usually employed when circulating a kick out, and since the hole in the drill stem may be quite small, detection of the problem may be difficult. If the location of the hole is determined to be below the kick, however, many operators recommend that circulation be continued until the kick has been circulated out. A change to the slower kill rate reduces the flow rate of mud through the hole in the pipe and reduces the likelihood of the hole’s being washed larger. Keeping the hole in the pipe from getting larger may make it possible to continue circulating the well without excessive back-pressure. A plugged bit When a well kicks and a large amount of barite and chemicals are added to the mud in the pits, and when mud in the pits is stirred during weight-up, it is possible for relatively large lumps of solid material to form. When circulated down the drill stem, these solid masses may totally or partially plug the jets of the bit. Fortunately, plugging is not common and, when it does occur, the jets usually are only partially plugged. When the bit plugs, either partially or totally, while circulating a kick out of the well, pump pressure suddenly goes up; however, casing pressure

remains relatively constant. It is important for the choke operator to recognize bit plugging and not to open the choke in an attempt to reduce SIDPP to its proper value. Opening the choke could reduce bottomhole pressure and allow the entry of additional formation fluids. If the bit is completely plugged, the following suggested methods could help to overcome the problem: 1. Rapidly increase, then decrease, the pump rate; the pressure surge may clear the jets. 2. Perforate the drill stem above the plugged bit. 3. Use a string shot near the bit; the shot may clear the jets. 4. Use a shaped charge near the bit; the explosion may clear the jets. If the bit is partially plugged, some operators suggest that the best course of action may be the following: 1. Stop the pump and close the choke to shut the well in completely. 2. Record SIDPP and SICP 3. Open the choke, start the pump, and bring its rate up to the original kill rate while keeping SICP constant. 4. When the pump is up to kill-rate speed, note SIDPP; it now becomes the new circulating pressure. If it appears that this pressure is too high for the pumps to handle, pick a new kill rate at a slower pump rate and repeat the steps

Other Problems In addition to a hole in the drill string and a plugged bit, other unusual situations can occur. An alert crew can often identify the problem by noting its effect on SIDPP , SICP , drill string weight, pit level, and pump rate. Table 1 shows several problems and their effects, as well as what occurs when a gas kick reaches the surface. As an example, note that a washed out bit nozzle causes SIDPP to decrease and the pump rate to increase. It has no effect on SICP , drill stem weight, or pit level. Pressure between Casing Strings When two or more casing strings exist in a well, and formation gas enters the wellbore, it is possible for the gas to become trapped in the annular space between the strings. Suppose, for example, that an intermediate (protection) liner is hung inside surface casing. Further, suppose that the liner hanger packing does not make a good seal between the liner and the casing in which the liner is hung. In such a case, formation gas can leak past the hanger’s packing and enter the annulus of the surface casing. A poor cement job can also allow pressure to be- come trapped between two casing strings. Cement voids around the casing shoe of the second string that extend upward, can allow formation gas to enter the annulus between the two casing strings. Also, a hole worn into a string of casing that lies inside another casing string can allow formation gas to become trapped inside the annulus between the two strings. In whatever way kick fluids enter the annulus between casing strings, they become trapped there as long as the annulus valve

at the top of the casing is closed. The danger comes when it is necessary to open the annulus valve to nipple down the BOP, set a new casing string, and the like. If the annulus valve is opened and gas is trapped behind it, the gas escapes suddenly with great force, which can harm or kill personnel and damage the rig. Crewmembers should therefore open the annulus valve slowly and carefully to bleed off any gas trapped in the casing annulus.

Pump Failure If a pump fails during the time a kick is being circulated out of the well, it is usually simply a matter of changing to a backup pump. Most operators require crew members to obtain kill rate pressures for all pumps on the rig, in case a pump fails. During the time required for changing to another pump, any gas influx will continue to rise up the hole, so it is important to maintain close surveillance of the casing pressure. If it approaches the maximum allowable shut-in pressure, it may be necessary to bleed pressure, using the volumetric method described in chapter 6. Recall that the volumetric method maintains constant bottom hole pressure by bleeding small measured amounts of mud from the annulus to control SICP. If all pumps fail, crewmembers can use the volumetric method to maintain control of the well while pumps repairs are carried out. Also, keep in mind that anytime a pump or other equipment malfunctions or fails, the foremost concern of the rig crew is to do everything possible to keep the well under control at all times.

BOP Failure Flange Failure Failure of the blowout preventer system can occur for many reasons. For example, a flange seal (the pressure-tight seal at the bottom of the annular BOP and on top and bottom of the ram BOPs) can fail, resulting in a high-pressure stream of fluid exiting with great force at the failure point. At the same time, back pressure on the well is reduced, and additional kick fluids can enter the well. If the failure occurs at the annular BOP’s flange, one solution is to close the pipe ram BOP (assuming that drill pipe is in the hole) after ensuring that the rams will close on the body of the pipe and not on a tool joint. Another possible solution is to pump a graded sealant into the wellhead and then bullhead down the annulus. Should the bottommost BOP be closed and flange failure occur there, then one solution may be to drop the pipe into the hole and close the blind rams. If the blind rams fail to hold, one possible last resort is to pump cement to plug the well. Most operators and contractors prepare emergency response plans (ERPs) for such possibilities; rig crews should follow their ERP. Weep-hole Leakage Most ram BOPs in a surface BOP stack have weep-holes. When the main seal of the ram shaft fails, hydraulic fluid leaks from the weep-hole. Because a failed shaft seal can lead to failure of a positive closure of the rams around the pipe or on open hole, manufacturers’ provide weep-holes to alert crewmembers to the problem. Manufacturers also provide a temporary way in which to repair the leak, because the leak could occur when the preventer is shut in on a kick. Usually, the BOP has a hex screw located at the weep-hole, which, when tightened, injects sealant to stop the shaft seals from leaking. Therefore, during a well-control situation, if leakage from a BOP’s weep-hole is noted, a crew member should use the proper hex wrench and screw in the weephole packing to stop the leak. Tightening the weep-hole packing is only a temporary measure. After the well is killed and routine operations resume, crew members should repair the preventer shaft seals. Failure of BOPs to Close When the BOPs fail to close, the chances are good that the hydraulic BOP operating unit (accumulator) has malfunctioned. Virtually all operating units have nitrogen precharged accumulator bottles, electric pumps, and pneumatic pumps that move hydraulic closing fluid through lines to the stack. Crew members should therefore be certain the charging system is operating as it should. If it is not, manual means of closing may be required. The ram preventers in some surface stacks can be closed by turning large wheels; a pipe ram can thus be closed around the pipe in spite of applying maximum closing pressure. It takes longer to close the BOP manually than with a hydraulic operating unit, so the kick influx will be large. If the BOPs cannot be shut manually, it may be necessary to manifold a high-pressure test pump or a cement pump to the stack’s closing lines. By connecting a test or other type of pump to the closing unit’s hydraulic system, it may be possible to close the preventers.

Failure of BOP Seals If, upon closing a preventer, the packing in the preventer fails to make a good seal around the drill pipe or, in rare cases, on open hole, immediate steps should be taken to close the well in completely. For example, suppose a kick is detected and crewmembers close the annular preventer, only to discover that the annular packing element is not properly sealing around the pipe in spite of applying maximum closing pressure. In this case, after ensuring proper space out, the pipe ram preventers should be closed. Once the ram preventers are closed, control of the well is maintained and, if required, the failed packing element in the annular preventer of a surface stack can be replaced. Flow problems downstream from Choke In the event that the flow line downstream from the choke being used to control the well plugs or otherwise becomes unusable, it will be necessary to switch to a backup choke and choke line. Because of the possibility of choke malfunction or difficulties in the line down- stream from a choke, most operators and contractors install backup chokes in the manifold. Because of the Difficulty of changing failed seals in subsea BOP stacks, more BOP elements (often including a second annular preventer) are often available. Ideally, another remote- Adjustable choke will be installed because they are very convenient to use in maintaining correct back-pressure on the well while the kick is being circulated out of the hole. If a remote adjustable choke is not installed, it will be necessary to use a manual choke. Also, if the well is being circulated through a mud-gas separator, it is possible for the line to the separator to become plugged. If this line becomes plugged, crew members may have to redirect the flow into the flare line and completely bypass the line to the mud-gas separator. Pressure Gauge failure Although rare, surface pressure gauges can malfunction or fail. For this reason, most rigs have several gauges that personnel can use to read shut-in drillpipe pressure, shut-in casing pressure, and pump circulating pressure. It is important to remember, however, that when changing from one gauge to another, it is necessary to take new readings because of gauge variation. For example, when changing from one pump pressure gauge to another, personnel should determine and record the pump pressure at the reduced circulating rate using the new gauge. In the same way, new readings should be recorded for drill pipe pressure and casing pressure gauges if they are involved. ANNULUS Blocked If the annulus becomes completely blocked (packed off) while a kick is being circulated, it is impossible for the mud and kick fluids to exit the well from the annulus. Should annular pack off occur, one possible action is to perforate the drill pipe at a depth above the pack off. After determining the mud weight required to kill the well at the depth of the perforations, the mud is circulated through the perforations and back to the surface. With the well under control, it may be possible to wash over the plug in the annulus and reestablish full circulation.

Pipe Off bottom When a well kicks during a trip, an error in procedure has occurred. When tripping out, mud must be put into the well to replace the drill stem, and the hole must take the proper amount of fill-up mud. If formation fluids enter the hole during a trip out, the hole will not take enough mud. Similarly, during a trip in, the proper amount of mud must be displaced from the well. Moreover, when no pipe is in the hole and formation fluids enter it, mud will flow from the well. An alert crew, therefore, will recognize that an influx has occurred and take steps to prevent further intrusions. If a well kicks while a trip is being made, pressure control measures can be more difficult, but the quicker the reaction to the problem, the less difficult the solution will likely be. A fullopening drill pipe safety valve, in side BOP, operating wrenches, and the proper crossover subs should be available immediately on the rig floor. Further, all equipment should be in good working condition and be placed on the floor where it can be installed quickly and correctly. Before the safety valve is installed, the annulus should be open. If the annulus is partially or completely closed, fluids from inside the drill stem will likely flow at such a high rate that it will be difficult or impossible to stab a safety valve. If the well kicks with the pipe off bottom, and if pipe can be stripped back to bottom, then the kick can be controlled with the mud weight in use when drilling before the trip. If the pipe cannot be stripped back to bottom, then a higher mud weight will be needed to kill well pressure with the shortened drill string. It is important that TVD to the bit and not TVD to the bottom of the hole be used when calculating the mud weight needed to kill the well. In many cases, the extra-heavy mud needed to kill the well with the shortened string may be enough to cause lost circulation. In any event, care must be taken to anticipate the consequences of moving volumes of original- and kill-weight muds when pipe is later run back into the hole. Pipe out of the hole If a kick occurs with the drill stem out of the hole, most operators recommend that the well be shut in immediately and preparations be made for stripping or snubbing the pipe back into the hole. During these preparations, it is also usually recommended that SICP be noted and recorded every 15 min. If SICP rises, which is likely if gas is in the kick fluids and migrates up the hole, the problem is aggravated. Migration of gas to the surface can cause an excessive increase in bottomhole pressure unless the gas is allowed to expand. The volumetric method of well control can be used to control casing pressure by bleeding fluid from the well to exactly compensate for increasing casing pressure. A float in the drill stem A float, or back-pressure, valve can be installed in the drill stem to prevent kick fluids from entering it. It is usually installed between the bit and the drill collar. One problem with drill pipe float valves is that if a kick is experienced and the well is shut in, SIDPP may read zero; or SIDPP may actually indicate some pressure. Regardless of the reading, however, it is not reliable, because accurate pressure indications from below cannot get through the closed valve.

(Available from several manufacturers are float valves with special ports that may allow SIDPP to be read without opening the float valve.) Since SIDPP is essential to most well-control procedures, it is necessary to determine its value. Several methods have been used to overcome the problem; the following is one: 1. Rig up a cement pump to pump mud into the drill stem. 2. While holding SICP constant with the choke, pump as slowly as possible and keep a close watch on SIDPP. It will rise to a certain value and then stop rising. When it stops rising, stop the pump. The pressure noted after the pump is stopped should be SIDPP. Other methods of determining SIDPP use the mud pump. One such method is to pump as slowly as possible until SICP starts to increase, then stop pumping. The pressure indicated on the drill pipe pressure gauge should be SIDPP. Normally, a drill pipe float valve is installed in a special sub, or float body, just above the bit. Circulating pressure overcomes spring pressure to keep the dart open. When circulation stops, the dart springs closed. Stripping and Snubbing operations To kill a well properly, the drill stem must be at or near the bottom. With pressure at the surface, it may become necessary to run the drill stem into or remove it from the well under pressure. This action is called stripping. When well pressure exerts so much upward force that the weight of the string is not sufficient to allow it to be stripped into the wellbore, then snubbing becomes necessary. Snubbing requires the use of special equipment to force the pipe through the preventer or preventers used in the stripping operation Preparing for Stripping Before any stripping operation begins, thorough preparations should be made to reduce the chances of error. The following procedure has been used successfully to prepare for a stripping job: 1. Reduce closing pressure on the annular pre venter to minimum sealing pressure. Except with subsea stacks, minimum sealing pressure is usually determined by allowing the preventer to weep fluid between the drill stem and the preventer packer. With subsea stacks, a table of operating characteristics for the preventer in use must be employed to determine minimum sealing pressure. 2. Record SICP. 3. Make sure that an inside BOP or an inside BOP and a drill pipe safety valve are available in good working order and in full open position. 4. If pipe is to be stripped out of the hole, install a back-pressure valve, or float, in the lower section of the string. 5. Remove all drillpipe casing protectors (rubbers) from the string before attempting to casing protectors strip in.

6. Rig up to use a hand-adjustable choke whether stripping in or out. 7. Use a trip tank for accurate measurement of mud volumes bled from or added to the well. 8. If stripping in, calculate the amount of mud to bleed from the well as the volume of drill pipe replaces the volume of mud in the hole. Remember to use the closed-end displacement of the pipe being run. 9. Be prepared to fill the drill string with mud periodically. 10. When the stripping operation involves the use of two preventers, the distance between them must provide sufficient clearance for tool joints. Moreover, when stripping in, bear in mind that the first joint stripped in will have an inside BOP and tool joint, or an inside BOP, drill pipe safety valve, and tool joint that must fit between the preventers. 11. Be aware of company policies in reference to stripping operations. Senior personnel may have to make decisions based on such policies and they must be prepared to adhere to them. 12. If the drill pipe has rubbers installed, consider carefully whether to strip out. Problems could arise if the rubbers strip off or accumulate under the preventers. 13. Since the life of the packing element in an annular preventer can be extended by limiting the maximum well pressure imposed on it, many companies set such limits during stripping operations. Some operators use a limit of 2,000 psi maximum well pressure for stripping; however, recent tests reveal that adequate performance is obtained from annular BOPs exposed to 3,000 psi during stripping operations. In any case, the crew should be aware of policy limits and adhere to them. Stripping into the Hole If the rig crew does not fully understand the strip- ping process and its limitations, then stripping into the hole can be a hazardous operation. Yet workover rigs with a minimum of equipment and small crews routinely strip in and out of a well with no difficulty. Therefore, senior personnel on a drilling rig have the responsibility of explaining to the crew exactly what they are, and are not, to do during a stripping job. Stripping in with Annular Preventer Stripping into the hole using the annular preventer is not difficult, but several recommendations should be kept in mind: 1. The pressure-regulating valve in the annular BOP system is designed so that hydraulic fluid can pass through it in two directions. Fluid flows through the valve and to the preventer to operate the preventer. Then, to allow the preventer to open slightly when a tool joint passes through it, fluid is reversed and flows back through the valve. Therefore, the pressure-regulating valve must be in good operating condition. Also, the lines from the valve to the annular BOP should be large enough to allow fluid to flow with a minimum of restriction. On subsea stacks, an accumulator bottle can be installed near the preventer to allow fluid to pass back into the

bottle freely. If stripping with the annular BOP is part of the company’s policy, a stack-mounted accumulator bottle should be considered 2. As stated before, use the lowest possible closing, or operating, pressure on the annular preventer. Low closing pressure helps prevent wear on the packer. The operating pressure should be reduced until the annular BOP weeps when the pipe is being stripped through it. 3. Keep water or oil on top of the packer as a lubricant. 4. Well pressure can be so high that it pushes pipe out of the hole or prevents it from being stripped in without a pull-down, or snubbing, device. To strip into the hole with an annular preventer, the weight of the drill stem must be greater than the pressure exerted upward against the tool joints by annular pressure. An equation is available that can be used to estimate whether the drill stem weighs enough to be stripped into the hole: WBF = (ODdp) 2 × 0.7854 × SICP + F WBF = wellbore force, lb.

ODdp = outside diameter of drill pipe, in.

SICP = shut-in casing pressure, psi

F = friction factor, 1,000 lb.

As an example, assume that— ODdp = 5 in.

SICP = 750 psi

Δ SICP = 20 × 17.33 + 1,000 = 1, 346.6 psi. Form any stripping jobs, simply holding SICP constant with the choke should be adequate. Because gas migrates up the hole, however, a correction may be needed; if so, these equations or similar ones can be used to calculate the correction. Every stand of pipe stripped into the hole should displace mud; if not, circulation has probably been lost. As pipe is stripped into the hole, the fluid in the hole gains in height because the pipe displaces the fluid. Since the volume of the hole and the pipe can be determined, as well as the displacement of the pipe, it is not difficult to calculate the gain in the fluid’s height. One equation that can be used follows: h = L × (Cdp + Ddp) ÷ AV h = height gain, ft

L = length of pipe stripped, ft

Cdp = drill pipe or drill collar capacity, bbl/ft Ddp = drill pipe or drill collar displacement, bbl/ft

AV = annular volume, bbl/ft.

As an example, assume that 2,500 ft of 5-in. 19.5ppf drill pipe with 6 ⅜ -in. tool joints is stripped into an influx in a 12 ¼ -in. hole. How much will the influx gain in height? To solve the problem, first use tables B1 and B2 in Appendix B to find the drill pipe’s capacity and displacement. In this example, the pipe’s capacity is 0.01776 bbl/ ft and its displacement is 0.00750 bbl/ft. Next,

determine the annular volume with 5-in. drill pipe in it. Annular volume equals hole diameter squared, minus pipe diameter squared, divided by 1,029.4. In this case, it is 12.252 – 52 ÷ 1,029.4 = 150.06 – 25 ÷ 1.029.4 = 125.06 ÷ 1.029.4 = 0.1215 bbl/ft. With annular volume known, use equation 64 to find the solution. Thus — h = 2,500 × (0.01776 + 0.00750) ÷ 0.1215 = 2,500 × 0.0253 ÷ 0.1215 = 63.25 ÷ 0.1215 h = 521 ft 5. If SICP does not stop rising even though mud displacement stops between stands, use the volumetric correction equations (equations 58 and 63). Stripping in with Ram Preventers Stripping into the hole using ram preventers requires good judgment and careful measurements. Ram BOPs can be used for stripping if the pressure in the annulus is too high to strip tool joints through the annular BOP, if rubbers on the drill pipe cannot be removed, or if the annular preventer is inoperable or unavailable. An estimate of how much the string has to weigh to be stripped into the hole successfully with ram BOPs can be made by using equations 60, 61, and 62. When determining the length of pipe required to make the proper stripping weight, however, a modification to the formula is needed. Since rams close on the body of the pipe instead of the tool joints, and since the tool joints cannot be stripped through closed rams, drill pipe OD should be used rather than tool joint OD. For example, with 5-in. 20.9-ppf drill pipe, an SICP of 750 psi, and a mud weight of 12 ppg, the lightest the string could weigh and still be stripped in with the ram preventers can be calculated using the following equation: WBF = (ODdp) 2 × 0.7854 × SICP + F

(Eq. 65)

WBF = wellbore force

ODdp = OD of drill pipe, in.

SICP = shut-in casing pressure, psi

F = friction factor, 1,000 lb.

As an example, WBF = 52 × 0.7854 × 750 + 1,000 = 25 × 0.7854 × 750 + 1,000 WBF = 24,873 lb. With 12-ppg mud in the hole, the buoyancy factor (using equation 61) is— BF = (65.5 – 12) ÷ 65.5

BF = 0.82.

With drill pipe that weighs 20.9 ppg, the minimum length required (use equation 62) is— Ldp = 24,873 ÷ (20.9 × .82) = 24,873 ÷ 17.14

Ldp = 1,451 ft.

Note that the length and weight required for stripping with ram preventers are less than required to strip through the annular preventer, because the upward wellbore pressure is acting against the cross-sectional area of the pipe rather than the tool joints; since the cross-sectional area of the

pipe is smaller than the cross-sectional area of the tool joints, wellbore pressure is acting on a smaller area and thus is lessened. If it is determined that pipe can be stripped using the ram preventers, the following procedure can be used: 1. Select the two rams to be used and measure from the rotary table to the top of the upper ram and to the top of the lower ram. (An annular preventer can be used in place of the top set of rams.) 2. Reduce the closing pressure on the rams to 500 psi or less. 3. With the upper ram closed, lower a joint of pipe slowly while measuring it until the tool joint is 2 ft above the upper ram. (On floating rigs, the distance must also be great enough to allow for vessel heave.) 4. Stop lowering and close the lower pipe ram. 5. Bleed off the pressure between the upper and lower rams and open the upper ram. 6. Carefully measuring the joint, lower it until the tool joint is between the two rams. 7. Stop lowering and close the top ram. 8. Using a test pump, pressure up the space between the two rams to the same value as well pressure. Open the bottom ram. 9. Continue the stripping process by going back to step 3 and repeating the steps. During the stripping operation, maintain constant SICP by bleeding mud though the choke. The mud displaced from the hole by the pipe can be measured and corrections made to get the exact annular pressure changes as pipe is stripped in. For most stripping jobs, holding casing pressure constant should be adequate; however, migrating gas may require corrections. During strip in, every stand of pipe should displace mud; mud displacement and the rise in pressure should stop when no stand is being stripped. If a stand does not displace mud, circulation has been lost. If the pressure does not stop rising and mud displacement stops between stands, use a volumetric correction equation (such as equation 58 or 63). Stripping Out of the Hole Stripping out of the hole follows the same general procedures as stripping into the hole; however, a drill pipe float or a pump-down inside BOP is necessary to seal the pipe before coming out of the hole. Strip- ping out of the hole with a gas kick should be care- fully reviewed before a decision is made to proceed; indeed, most operators do not recommend stripping out with gas in the wellbore. Snubbing When the upward force that is generated by wellbore pressure acting on the cross-sectional area of the tool joints or drill string is greater than the weight of the drill string, snubbing equipment should be rigged up to force the pipe into the well through the preventers. Equations 60, 61, and

62 can be used to confirm how much pipe will have to be snubbed before stripping operations can commence. Before snubbing operations begin, thorough preparations should be made to ensure that all of those involved in the operation know their duties and positions. A review of the operator’s and contractor’s procedures is essential and all equipment must be in good working order. In general, the same preparations that are made for stripping operations should be made for snubbing. Two general types of snubbing, or pull-down, units are available: mechanical and hydraulic. Whether a mechanical or a hydraulic unit is used, the usual procedure is to snub pipe into the hole until the pipe’s weight is sufficient to allow stripping operations to begin. Usually, the pipe will start to fall through the snubbers by means of its own weight. Once the pipe begins to fall of its own weight, strip- ping procedures can be followed. Keep in mind that comparatively high casing pressure will continue at the surface. Mechanical Snubbing Units Available in several sizes, mechanical units are de- signed to use the hoisting equipment on the rig. The smallest units are capable of exerting about 50,000 lb of force. Larger sizes range upward to units capable of exerting 350,000 lb of force. One type relies on rig power to snub pipe in or out of the hole through a system of pulleys and cables controlled by the rig’s drawworks. Basic components of a typical mechanical unit are the blowout preventers, or control heads; stationary and traveling snubbers; operating manifold; power package; snub line; and balance weights. Downward thrust to force pipe into the hole against well pressure is achieved by means of the pulley system. Raising the traveling block causes the traveling snubbers that grip the pipe to move down and pull pipe into the hole. After each downward stroke, the stationary snubbers attached to the top control head grip the pipe until the traveling snubbers are raised or lowered to grab another portion of the pipe. Flow around the pipe is shut off by three hydraulically controlled control heads. The two up- per heads are opened and closed to lubricate pipe in or out of the hole. The bottom head is closed to change packing in the upper heads. Drill pipe must be plugged by use of a landing nipple and plug assembly, slip-type plug, or bridge plug, depending on whether pipe is being run in or pulled out of the hole. Hydraulic Snubbing Units Most hydraulic units are self-contained and thus are operated with or without the rig’s being in place on the well. One such unit features a blowout preventer, or control-head, stack similar to that used on a mechanical unit. A multi cylinder hydraulic jack raises or lowers traveling slips that grip the pipe and snub it into or out of the hole. Stationary slips below the traveling slips hold the pipe in place while the traveling slips are being repositioned on the pipe prior to another pull. An integral stripper controls pressures up to 3,000 psi. The control heads are used if pressures higher than 3,000 psi are involved and as a backup to the stripper. All operations are carried out at a control console in the work basket. Pipe reciprocation during a well kill Most operators and contractors stress that the first concern during a well killing operation is to gain control of the well first and worry about other problems, such as sticking the drill stem, later. If it becomes necessary, however, to reciprocate (move up and down) the drill stem during

a well killing operation, it is important to pay attention to detail. If the annular preventer is closed on the well, the lowest possible closing pressure should be used to prevent as much wear as possible to the packing element. The same holds true for ram preventers. Also, the weight of the drill stem must be heavy enough to overcome the upward force of well pressure; otherwise, it is not possible to strip the drill stem downward into the well—it will have to be snubbed (see the earlier discussion of stripping and snubbing in this chapter). Further, moving the drill stem when the well is closed in on a gas kick is not without risk, because gas continues to migrate upward and increase SICP during the period of pipe reciprocation. Lost Circulation Lost circulation is a condition in which whole mud is lost to a formation. Well kicks cause additional pressure in the hole, so special care should be taken to avoid or to minimize lost circulation during a well kick. Most well-control procedures are designed for the purpose of circulating heavy mud to kill the kick. If circulation is lost, it can be difficult or impossible to circulate the annulus full of heavy mud. When a well is shut in after a kick, SIDPP is used to calculate the mud-weight increase needed to kill the kick. Shut-in pressures can also indicate the likelihood of lost circulation. The way to find out if circulation has been lost is to attempt to circulate mud; if returns are reduced or fail to come back to the surface at all, it is safe to assume that circulation is lost. Conditions for Lost Circulation In general, three conditions are responsible for lost circulation: bad cement jobs, induced fractures, and vuggy or fractured formations. Bad Cement Jobs One of the most common causes of lost circulation during a well kick is a bad cement job at the base of the last string of casing run into the well. Because a bad cement job can cause lost circulation, most operators run leak-off or pressure-integrity tests just after drilling out the shoe to determine the pressure at which fracture occurs. The test is usually conducted to determine the highest mud-weight equivalent that is expected to be used before the next string of casing is set; sometimes the test is carried out to pressures set by statutory requirement. In any case, a poor cement job is especially hazardous, because it may allow kick fluids to broach around the casing and under the rig. Major losses both on land and offshore have occurred because gas surfaced around the casing. Induced Fractures Fractures that are induced by drilling and well-control procedures can also cause lost circulation. Such fractures can be caused by pressure surges, mud weight that is too high, or other wellcontrol procedures. In most cases, induced fractures close, or heal, on their own in a short period of time if pressure is relieved. Induced fractures occur at the weakest point in the hole—usually at the casing shoe; therefore, an induced fracture can cause the same problems associated with a poor cement job.

Vuggy or Fractured Formations When drilling in hard-rock country, some formations are vuggy; that is, they have large natural openings into which vast amounts of whole mud can flow. Naturally fractured formations can also take mud in high quantities. Such formations are difficult or impossible to seal and awaiting period often does not help. Many times, the entire formation is vuggy or fractured, so that the pressure required to kill the well is very close to the pressure that causes lost returns. Well Control with Partial Lost Returns Lost returns during a well kick can first be detected when mud level in the pits drops. If some returns continue to come back to the surface, several techniques are recommended by wellcontrol personnel: 1. After notifying the supervisor, crewmembers can try to keep the mud volume up by mixing.

The pressure on the zone of lost returns will go down after the intruded kick fluids are circulated above the zone, so the problem may solve itself. 2. Some well-control operators recommend that the pump be stopped and the well shut in if the lost circulation continues to worsen. If the hole is given from 30 min to 4 hr to sit quietly, the lost circulation problem may cure itself. With this technique, most operators recommend keeping SIDPP constant by relieving choke pressure. If choke pressure goes up by more than 100 psi, some operators recommend that the next technique be tried. 3. Pick a slower circulating rate and a new initial circulating pressure. With the pump stopped and the well shut in, open the choke, start the pump at the new, slower rate, and close the choke until annular pressure is the same as when shut in. (With subsea wellheads, reduce annular pressure by the amount of choke-line friction loss.) Then shift to the new initial circulating pressure on the drill pipe. 4. Mix a slug of lost circulation material that is effective in the area. In general, lost circulation material is more effective in hard-rock country than in areas where the rocks are plastic. 5. Mix a slug of heavy mud to try to kill the kick. A heavy mud slug may work with a small kick if the zone of loss is well above the zone that is kicking. After the kick is killed, solve the lost circulation problem. 6. If severe partial returns (60%to90%loss) cannot be stopped, use a barite or gunk plug to seal off the kick zone, then work on the lost circulation problem. Barite Plugs Sometimes, after a kick has occurred and is being circulated out of the well, lost circulation occurs. Lost circulation can present a complex and dangerous condition in that gas could be replacing drilling mud (drilling mud is, of course, the first line of defense against blowouts). If a plug can be placed in the wellbore to seal off the zone that is giving up gas, the lost circulation problem can be worked on. Barite plugs with weights of 18 ppg to 22 ppg have been found to be effective in controlling active zones. A barite plug usually consists of barite, fresh water, and a

thinner slurry. The plug is spotted as close to the active zone as possible. A barite plug should have high density—up to 22 ppg—a rapid settling rate, and a high filter loss. Finally, it should be large enough to fill about 500 ft of open hole. By increasing the density of the mud up to 22 ppg using barite, the increase in hydrostatic pressure may control the pressure in the formation. The plug of barite, sodium acid pyrophosphate (SAPP), and caustic soda should be mixed in fresh water. Barite is the weighting material, SAPP is a thinner, and caustic raises the pH of the water. The components are mixed to form the 18 ppg to 22 ppg slurry. Hydrostatic pressure must be sufficiently high to stop the flow; otherwise, the barite cannot settle out to form a solid plug. Materials with densities higher than barite, such as hematite, ilmenite (limonite), and galena, can also be used to mix plugs. Even though cement can be used, it may be difficult to set a plug that will hold, because gas influxes tend to channel cement. To spot a barite plug successfully, special mixing and pumping equipment, such as a cement hopper and a high-capacity cementing pump, are required. Pilot testing should also be conducted to ensure that the quantities of SAPP and caustic added to the slurry are sufficient to allow the barite to settle out properly. If the barite settling rate is too slow, more SAPP can be added to speed the settling rate. The following is one recommended procedure for mixing a barite plug: 1. Prepare to mix the barite slurry through the hopper of the cementing unit and to pump directly into the drill pipe. 2. Calculate the volume required to yield a settled plug of barite 500 ft long in open hole. If necessary, increase the volume to allow for severe hole washouts (see table 2). 3. Mix about 0.7 lb of SAPP per bbl of fresh water. 4. Adjust the pH of the freshwater to9withcaustic soda; use about 0.25 lb of caustic for every bbl of water. 5. Mix the barite plug to achieve a slurry weight of 18 ppg to 22 ppg, preferably 22 ppg. Once the slurry is mixed, the following suggestions for pumping it may be employed: 1. Pump the barite slurry at a rate of 5 bbl/min to 10 bbl/min. 2. Under displace the slurry mixture by about 2 bbl to 4 bbl to avoid contamination by drilling fluid. 3. Displace the barite slurry out of the drill stem with a high-density slug to reduce the possibility of backflow and bit plugging. 4. Rapidly pull one stand of pipe; continue tripping pipe out of the hole until the bit is above the top of the barite plug. It may be necessary to strip the pipe out. 5. Hold back-pressure on the annulus. 6. When the bit is above the barite plug, begin circulating while continuing to hold back-pressure on the well.

7. Wait for the barite to settle and form a solid plug. The length of the wait depends on the additives in the slurry. 8. To determine whether the plug is holding, circulate the well using the first circulation of the driller's method and check the returns. If returns are free of gas, the high-pressure zone has very likely been properly sealed off by the barite plug. Once the underground flow problem is solved, attention can be turned to solving the lost circulation problem.

Gunk Plugs For underground water flows, gunk plugs have been successful in providing a seal in the annulus. A gunk plug is a mixture of diesel oil and bentonite. When dry bentonite is added to diesel oil, the bentonite does not yield, and the slurry remains very fluid; thus it can be pumped to the bit with relatively low pressure. When the slurry leaves the bit and is exposed to the water in the annulus, the bentonite hydrates, or swells, rapidly and causes the slurry to become extremely viscous. Its extreme viscosity slows formation flow and, as more slurry enters the annulus, seals completely. One recommendation is that the bentonite-diesel oil slurry be jet mixed with a cementing unit to 11.0 ppg. To make this weight of slurry, use about three sacks, or 300 lb, of bentonite per bbl of diesel oil. Some operators also prefer to add about 15 lb of mica per bbl to increase the strength of the plug. The volume of slurry to be pumped usually ranges from 20 bbl to 150 bbl, depending on the rate of underground flow and the amount of open hole. The biggest problem in using gunk plugs is the danger of the slurry’s contacting water inside the drill stem. If this happens, the bentonite hydrates, causes excessive pump pressure, and usually plugs the drill stem. It is important, therefore, that not only the drill stem but also the pumping and mixing equipment be free of water. To avoid plugging problems in the drill stem, it is recommended that diesel oil spacers be pumped ahead of and behind the slurry. Gunk plugs tend to lose strength with time under downhole conditions; therefore, many operators recommend that cement slurry be squeezed through the bit to provide a permanent seal as soon as it has been determined that underground flow has been shut off. The following procedure has been used successfully to spot a gunk plug across a lost circulation zone:

1. Run survey tools, such as flow and temperature logs, to locate the flowing or lost circulation zone accurately. 2. Rig up both the cementing unit and the rig pumps so that either can be used to displace the slurry. Some operators also recommend that a third pump be connected to the annulus to pump down the annulus to keep casing pressures low. 3. Using a cementing unit, jet mix the slurry to11.0 ppg. The slurry can be batch mixed or mixed on the run. 4. Pump 5 bbl to 10 bbl of diesel oil into the drill stem to serve as a spearhead, or spacer, between the drilling mud and slurry. 5. Displace the slurry down the drill stem at a rate of 3bbl/min to5bbl/min. Follow the slurry with a 10 bbl to 20 bbl diesel oil spacer. 6. When the slurry reaches the bit, begin pumping water-base mud down the annulus at a rate of ½ bbl/min. Pumping water-base mud down the annulus lowers surface pressure and could provide water for slurry hydration. 7. Wait from 6 hr to 8 hr, or run a temperature survey to determine whether the plug is effective. 8. Release pressure on the annulus and pull the drill stem slowly. 9. Squeeze cement through the bit to provide a permanent seal. Excessive Casing pressure In the drilling industry, maximum allowable surface pressure (MASP) can range from zero to as high as 100 percent of the casing burst rating. Regardless of how MASP is determined, when a large gas kick is circulated out, the fracture pressure at the casing seat, or MASP, may be exceeded. Decisions on whether to shut the well in when pressures exceed stated limits should be based on casing design and the depth at which it is set, knowledge of the characteristics and contents of the formation, company policies, and prior analysis of the possible consequences of different courses of action. Accurate calculation of pressures in a well at various depths is difficult, because such calculations are based on the assumption that gas migrates or is circulated up the hole in slug or bubble form. Experience has shown that gas does not move upward as a slug or bubble; rather, it tends to disperse into the drilling fluid, the extent depending on the type of gas and type of mud in the hole. Because gas disperses unevenly over the length of the annulus, pressure calculations cannot be accurate; therefore, the decision on whether to shut in when pressure limits are reached must be based on factors that often cannot be calculated accurately.

Bullheading Bullheading into a well is forcing gas or other wellbore fluids back into a formation by pumping into the annulus from the surface. The well remains closed in so that mud and kick fluids are displaced into the weakest exposed formation. Bullheading is not a routine procedure, but it may

be useful when anticipated surface pressures are expected to exceed the pressure limitations of the surface equipment, when kick fluids are hazardous if circulated to the surface, when the drill pipe is plugged or parted so that kill mud cannot be circulated to bottom, or when a weak zone below the kick takes mud too fast for the well to be killed. Bullheading is perhaps most appropriate for wells with very short open-hole sections, since in such cases the influx is most likely to be squeezed back into the formation from which it came. When bullheading, the pumping rate must exceed the rate at which the gas migrates up the hole to clean the annulus. One indication of too low a pumping rate is an increase, rather than a decrease, in pump pressure. To determine the required pump rate, the rate of gas migration must be calculated. One way in which to calculate the gas migration rate is to use equation 31: Rgm = Δ SICP ÷ MG (Eq. 31) Rgm = rate of gas migration, ft/h

ΔSICP = change in SICP after 1 h, psi

MG = mud gradient, psi/ft. Ideally, bullheading will fracture a formation, and continued pump pressure will force gas back into the formation. Anytime high pressure is applied at the surface, however, formation breakdown at the casing shoe, rather than at a formation lower in the hole, is possible. Should fracture at the shoe occur, an under- ground blowout may develop, and broaching around the casing is a possibility. Therefore, bullheading is not without risk, and caution should be exercised whenever the procedure is used. Snubbing into the drill stem Under certain circumstances, small-diameter tubing may have to be snubbed into the drill stem. For example, assume that a well is shut in and is being circulated, and that a large hole or a washout occurs in the drill stem. Further assume that the washout is very large and is at a depth in the drill stem that makes it impossible to continue to circulate the well. One solution is to snub small-diameter tubing into the drill stem to reestablish circulation. One way to snub tubing is with a coiled tubing unit. A coiled tubing unit is a portable machine that eliminates the need for making up and breaking out individual tubing joints, since the unit’s tubing is a continuous length of small-diameter pipe coiled onto a reel. Coiled tubing ODs generally range from ½ in. to 2 in. The primary advantage of coiled tubing is that it affords a great savings in time, since individual joints of tubing do not have to be made up during the snubbing operation. Further, coiled tubing units are light in weight and are equipped with blowout preventers and other pressure-control devices that make them ideal for snubbing. A disadvantage is that coiled tubing has relatively low collapse and yield strength. In high-pressure situations, therefore, the tubing may collapse or burst. Also, a coiled tubing unit does not allow the tubing to be rotated. If a coiled tubing unit cannot be employed, then it may be possible to snub small-diameter, individual tubing joints into the drill stem. A special snubbing unit that maintains pressure control as the tubing is snubbed into the drill pipe is required. Although snubbing tubing a joint

or a stand at a time into the drill stem takes longer than snubbing with coiled tubing, jointed tubing can be rotated and it is stronger.

Underbalanced Drilling Underbalanced drilling is drilling ahead while a formation in the well is kicking (producing). In cases where the influx is of relatively low volume, it is sometimes possible to seal the annulus of the well with a rotating head or a rotating annular BOP and drill ahead. They provide a way to seal around the Kelly, or in the case of top drives, around a joint of drill pipe, while the Kelly or pipe is rotating. Usually, high penetration rates are achieved because the influx of fluids from the formation moves cuttings rapidly away from the bit, allowing its cutters to remain in constant contact with uncut formation. In other words, the bit cutters do not have to re-drill old cuttings that have not had time to be moved away from the bit. What is more, underbalanced drilling into the zone to be produced reduces formation damage allowing increased production when the well is completed. Another benefit of underbalanced drilling is the reduced risk of differential sticking of the drill stem.

Rotating Heads A typical rotating head consists of a bowl, stripper rubber, bearing assembly, and a Kelly driver. The rubber and bearing assembly form a pressure-tight seal in the bowl. On rigs using Kellies, the Kelly fits inside the Kelly driver, which, in turn, seats in the bearing assembly. Annular fluids exit through the outlet on the side of the bowl. Normally, drilling fluid and gas go to a mud-gas separator, where the gas is flared and the mud returned to the active system.

Rotating Annular Preventers A rotating annular preventer, like a rotating head, seals around the Kelly or drill pipe and allows the Kelly or pipe to rotate. One type of rotating annular BOP uses a packing element to seal around the drill stem member when hydraulic pressure is applied below the packer, much as in a conventional annular BOP. However, in the rotating annular, an interior assembly rotates within the preventer body as the drill stem rotates. Returning fluids exit the well through a return line mounted in the stack below the rotating annular

Other special well-control considerations Slim Holes To reduce costs, many wells are being drilled with coiled tubing units and with conventional drill stem and bits that are relatively small in diameter (slim). Indeed, some well diameters are less than 3-in. From the standpoint of well control, the main concerns with small-diameter holes is that intruded gas and other fluids extend long distances up the hole and circulating times are reduced; in short, fluid movement occurs rapidly. Tapered Holes and Tapered Strings A tapered hole is a wellbore that has sections that are drilled with different diameters; in fact, most wells are tapered. The top part of the hole is large in diameter, the middle parts are of

medium diameter, and the last, deepest part is small in diameter. Tapered strings are drill strings that vary in diameter. Sometimes, drill pipe and drill collar IDs can vary widely over the depth of a well. For example, a drill pipe string might be made up of 3 ½ -in., 4-in., 4 ½ -in., and 5-in. OD elements. Drill collar ODs and IDs can also vary. The main concern to keep in mind with tapered strings and tapered holes is that fluids extend over longer distances in small diameters and over shorter distances in large diameters. As a result, fluid flow happens quicker in small diameters than in large diameters. Another concern in tapered hole is to remember that when rising gas goes from a narrow diameter to a larger diameter section of annulus, SICP will drop because the gas may occupy less vertical space in the large diameter section. This drop may lead well-control personnel to believe that lost circulation has occurred.

Horizontal well-control considerations Horizontal wells present some unique well-control conditions. For one thing, crewmembers handling a kick in a horizontal well must remember that measured depth (MD) is quite different from true vertical depth (TVD). For another, drilling through a formation horizontally can expose long sections of hydrocarbon formations, making inflow potential during a kick much greater. Also, drilling through a long section of exposed formation increases the flow potential of the well. Because so much formation is exposed to the wellbore, when a kick occurs its volume can be very large, even if the crew detects it quickly and promptly shuts in the well. Kicks may be hard to detect in the horizontal portion of the well. Gas separates and migrates from other formation fluids when drillings tops. As a result, gas can accumulate in pockets in the top part of the horizontal borehole. This accumulation of gas in the upper parts of the hole, as well as in wash-outs and vertical fractures in the formation, may disguise the size of the kick. Crew members may not recognize a kick until enough gas has filled the upper sections of the horizontal hole and then begins to flow into the vertical part of the hole. In short, a large volume of gas may enter the well before the well is shut in. As a result, SICP may reach or exceed MASP. After gas separates and migrates to the top of the horizontal hole, it stops migrating. So, with a gas kick, SIDPP and SICP should stabilize after the well is shut in, if the gas portion of the kick does not extend to the vertical section of the hole. If gas does extend into the vertical and nearvertical hole portions, gas migration occurs and SIDPP and SICP increase accordingly. Further, if the influx is entirely in the horizontal part of the well, then hydrostatic pressure in the annulus and drill stem are the same, so SIDPP and SICP are the same or very close to the same. On the other hand, if SICP is higher than SIDPP, then the gas is also in the curved and vertical section of the hole. As mentioned earlier, in horizontal wells, kicks can occur anywhere along the long horizontal path of the wellbore, which means that a kick can occur at a shallower MD than normally expected. As a result, gas can reach the surface much sooner than expected. What is more, a kick can enter weak zones, such as faults, vertical fractures, and formation vugs (openings) along the horizontal wellbore, which means that accurate pressure readings cannot be obtained at the surface. After shutting in a horizontal well, crewmembers should look for fluctuations in SIDPP

and SICP. Lost circulation immediately after shutting in a horizontal well is possible, which could lead to an underground blowout and stuck pipe in the horizontal section. When drilling a horizontal well underbalanced, a rotating head or a rotating annular preventer is used to control the formation flow. The head or annular BOP behaves as a choke, in that it exerts back-pressure against the well, and it may therefore cause lost circulation. If the well is kicking, kick pressure may also cause the kick fluids to enter a weak zone. When the pumps are shut down, circulating pressure loss in the annulus and back-pressure created by the rotating head are lost. Under these circumstances of reduced bottomhole pressure, it may be possible for the fluids lost to the weak formation to reenter the well. When circulating a kick out of a horizontal well and maintaining constant bottom hole pressure, a gas influx in the horizontal section of the hole will expand little if at all. Thus, very little choke adjustment is required. Once the gas influx is circulated in the vertical section, however, it expands and choke adjustments become necessary to maintain constant bottomhole pressure. Also, in a well with a long horizontal section, gas may be more strung out than it is in a vertical well. Gas will therefore vent from a horizontal well for a longer period than from a vertical well. In horizontal wells, the placement of drill stem elements is often the reverse of the placement in vertical wells. That is, drill collars, if used, are near the surface, heavy-walled drill pipe is below the collars, and drill pipe and the bottomhole assembly tools are below the heavy-walled drill pipe. Therefore annular velocities and volumes are reversed as well—that is, annular velocities and volumes are lower near the bottom than they are near the surface, which is the opposite of the situation in a vertical well. Specifically, when the influx reaches the heavy-walled drill pipe and collars in the vertical section, the influx elongates and its velocity increases because the clearance (space) between the pipe and wall of the hole is reduced. As the gas elongates, hydrostatic pressure in the annulus is reduced, which, if not offset by quickly adjusting the choke, leads to another influx. The choke operator must be alert and quickly adjust the choke to maintain proper bottom hole pressure and to minimize pressure on the casing shoe. Many horizontal wells are drilled underbalanced, or, as engineers say, they are produced while drilled. Drilling underbalanced is also termed pressurized drilling. In any case, allowing a well to produce while it is being drilled minimizes formation damage. Formation damage can occur when the solids in a drilling mud, which is being circulated at a pressure higher than the formation with which it is in contact, reduce the formation’s porosity and permeability. The higher hydrostatic pressure of the mud forces the solids into the formation, which is lower in pressure. Formation damage can therefore often be minimized by keeping hydrostatic pressure lower than formation pressure. To drill underbalanced, a rotating head or a rotating blowout preventer seals the annulus of the well against pressure while at the same time allows the Kelly or drill stem to rotate and put weight on the bit. Usually, the rotating head is mounted on top of the BOP stack. Normally, a well can be drilled under balanced as long as the volume of production from the formation is not too high. The produced fluids exit the well through a line to a mud-gas separator and the physical size limitations of this flow equipment limits the volume they can handle. A well can be killed

while drilling underbalanced, using conventional means. If the well has vertical fractures, however, the kill fluid may go into empty or depleted fractures, and make it difficult to kill the well. Bear in mind that when a kick occurs in a horizontal well, it is important to know the well’s TVD. A horizontal well always has an MD that is longer than TVD. TVD is, however, used to calculate the density of the kill-weight mud. On the other hand, MD is used to calculate hole volumes.

Killing Horizontal Wells The wait-and-weight method is widely used to control wells (see chapter 6). In theory, the waitand-weight method regains control of the well in one circulation. In reality, however, and especially in horizontal wells, two or more circulations are needed. More circulations are usually needed because of inefficient hole displacement, gas pockets, and uneven ascent of gas to the surface. The wait-and-weight method often uses a chart or graph of calculated values to predetermine the drop in SIDPP. As kill-weight mud is pumped down the drill stem. Calculating the values for the graph assumes (1) that the length of the column of kill-weight mud increases the same amount for each incremental increase in pump strokes and (2) that the true vertical height of the kill-weight mud column increases the same amount for each incremental increase in pump strokes. The first assumption is true as long as the ID of the drill pipe is all the same and that the ID of heavy-walled drill pipe, and drill collars are the same as drill pipe ID. The second assumption is true as long as the hole is vertical and the first assumption is correct. Usually, any differences in ID often are not significant enough to make a big difference in plotting the pressure decrease in the drill stem as heavy mud is pumped down it. While killing in directional or horizontal wells, SIDPP decreases just as it does in a vertical well until the mud reaches the bottom of the kick-off point, KOP. At the bottom of the KOP, SIDPP should be the same as final circulating pressure, since TVD has been achieved. However, killweight mud still has to fill the drill string. Thus, at the bottom of a horizontal well’s radius, where the well becomes horizontal, SIDPP may be slightly below FCP.SIDPP May be lower than FCP because the kill-weight mud’s hydrostatic pressure has reached TVD but the pressure caused by friction losses through the string are not realized until the kill mud reaches and exits the bit. Because it is more difficult top lot the SIDPP’s pressure drop when using the wait-and-weight method in horizontal drilling, many contractors and operators prefer using the driller’s method. As described in chapter 6, in the driller’s method, the pumps are brought up to kill-rate speed, SICP is adjusted to its stable, pre-circulation value, and the well-control operator holds SIDPP constant until the kick is circulated out. Depending on the reach of the horizontal well, it may require a considerable amount of circulating to displace the influx from the horizontal portion

Procedure for Off-Bottom Kill As mentioned earlier, when pipe is off the bottom and cannot be stripped back to bottom, killing the well to the depth of the pipe may be necessary. This procedure is often called an off-bottom

kill and consists of using the depth to the bottom of the pipe (not the hole) to determine how much to weight up the mud to kill the well. Similarly, when a kick occurs in a horizontal well, it is particularly important to keep in mind that TVD and not measured depth is used to determine the weight of kill-weight mud.

Gas Behavior in Horizontal Section A horizontal well is virtually never perfectly horizontal; instead, it tends to vary up and down from horizontal, which results in portions of hole that arch upward and downward. What is more, some horizontal holes are intentionally deflected upward into a formation at a depth higher than the horizontal section. Gas influxes can become trapped in upward arching portions of the hole, as well as in portions of the hole deflected upward, because gas is lighter than drilling fluid and rises to the top of the arched hole. This gas tends to stay there—drilling fluid bypasses it and does not move it up to the surface, particularly if circulating at reduced pump rates. It is important to anticipate that an increase in pump rate when returning to drilling may sweep gas into the vertical hole, essentially behaving as another gas kick that may require careful circulating to remove.

Thief and kick zone combinations In some cases, a formation is exposed to the wellbore that, when the drilling mud is weighted up to kill a kicking formation or zone, breaks down (fractures) and circulation is lost, either partially or completely. The formation into which wellbore fluids are being lost is called a thief zone. A thief zone can occur above or below a kick zone. Either situation complicates well control operations. Where (1) the thief zone is above the kick zone, (2) the losses are partial, and (3) crew members can mix enough mud to replace that being taken by the thief zone, one procedure is to continue normal kill procedures—that is, maintain the kill rate pump speed and SIDPP as determined earlier. This procedure maintains a constant bottomhole pressure above that of the kicking formation. Once the kick fluids go above the thief zone, the zone may heal. If, however, the loss rate is so high that not enough mud can be mixed to replace that going into the thief zone, another procedure is to add lost circulation material (LCM) to the mud and circulate it into the well. LCM includes such substances as mica flakes, walnut hulls, and other materials that can plug the permeability of the thief zone. Keep in mind that it may not be possible to pump LCM through small bit nozzles or other restrictions in the drill stem. In fact, many well-control specialists recommend installing a special circulating sub in the drill stem in areas where a kick and lost circulation may be expected. If it is not possible to pump LCM, another way to handle lost circulation is to stop pumping and shut in the well completely. Sometimes, thief zones can heal themselves if given enough time in a static condition. Solids in the mud opposite the thief zone may plug the zone’s permeability. One indication that the zone has cured itself is that SIDPP and SICP will stop decreasing. (Recall that one indication of lost circulation is that SIDPP and SICP drop and do not respond as they should to choke adjustments.) If the problem continues and circulation losses become severe or complete, it may be necessary to set a barite or gunk (cement) plug to heal the zone, as covered earlier in this chapter.

Sometimes, a thief zone can exist below a kick zone. While drilling into the thief zone, lost circulation occurs, which may cause the upper kick zone to flow. If the mud weight is lowered to avoid losses into the thief zone, the upper zone would kick, but control would be easy since the thief zone has not been penetrated. Most contractors and operators agree that the primary concern is to control the well, so upon seeing the signs of the kick, the driller should shut in the well. If the pressure of the shut-in well is high enough to cause mud to flow into the lost circulation zone, SIDPP may be zero because the drill stem is full of mud, the kick zone is not at the bottom of the hole, and mud is being lost at the bottom of the hole. SICP may, however, be well above zero; the value for SICP depends on the size and fluid content of the kick

DAY-2 --------------- Session - IV Lost circulation Loss of circulation is the uncontrolled flow of whole mud into a formation, sometimes referred to as a “thief zone.” This article discusses causes, prevention, and remedial measures for lost circulation. Lost-circulation zones Fig. 1 shows partial and total lost-circulation zones. In partial lost circulation, mud continues to flow to surface with some loss to the formation. Total lost circulation, however, occurs when all the mud flows into a formation with no return to surface. If drilling continues during total lost circulation, it is referred to as blind drilling. This is not a common practice in the field, unless all of the following criteria are met:    

The formation above the thief zone is mechanically stable. There is no production. The fluid is clear water. It is economically feasible and safe.



Fig. 1—Lost-circulation zones. Causes of lost-circulation zones There are several situations that can result in lost circulation:   

Formations that are inherently fractured, cavernous, or have high permeability Improper drilling conditions Induced fractures caused by excessive downhole pressures and setting intermediate casing too high

Induced fractures Induced or inherent fractures may be horizontal at shallow depth or vertical at depths greater than approximately 2,500 ft. Excessive wellbore pressures are caused by high flow rates (high

annular-friction pressure loss) or tripping in too fast (high surge pressure), which can lead to mud equivalent circulating density (ECD). Induced fractures can also be caused by:   

Improper annular hole cleaning Excessive mud weight Shutting in a well in high-pressure shallow gas Eqs. 1 and 2 show the conditions that must be maintained to avoid fracturing the formation during drilling and tripping in, respectively. .................... (1) .................... (2) Where λmh = static mud weight, Δλaf = additional mud weight caused by friction pressure loss in annulus, Δλs = additional mud caused by surge pressure, λfrac = formation-pressure fracture gradient in equivalent mud weight, and λeq = equivalent circulating density of mud. Cavernous formations Cavernous formations are often limestone with large caverns. This type of lost circulation is quick, total, and the most difficult to seal. High-permeability formations that are potential lostcirculation zones are those of shallow sand with permeability in excess of 10 Darcies. Generally, deep sand has low permeability and presents no loss-of-circulation problems. In non-cavernous thief zones, mud level in mud tanks decreases gradually and, if drilling continues, total loss of circulation may occur. Prevention of lost circulation The complete prevention of lost circulation is impossible, because some formations, such as inherently fractured, cavernous, or high-permeability zones, are not avoidable if the target zone is to be reached. However, limiting circulation loss is possible if certain precautions are taken, especially those related to induce fractures. These precautions include:      

Maintaining proper mud weight Minimizing annular-friction pressure losses during drilling and tripping in Adequate hole cleaning Avoiding restrictions in the annular space Setting casing to protect upper weaker formations within a transition zone Updating formation pore pressure and fracture gradients for better accuracy with log and drilling data

If lost-circulation zones are anticipated, preventive measures should be taken by treating the mud with loss of circulation materials (LCMs) and preventive tests such as the leakoff test and formation integrity test should be performed to limit the possibility of loss of circulation.

Preventive tests Leak off test (LOT) Conducting an accurate leak off test is fundamental to preventing lost circulation. The LOT is performed by closing in the well, and pressuring up in the open hole immediately below the last string of casing before drilling ahead in the next interval. On the basis of the point at which the pressure drops off, the test indicates the strength of the wellbore at the casing seat, typically considered one of the weakest points in any interval. However, extending an LOT to the fractureextension stage can seriously lower the maximum mud weight that may be used to safely drill the interval without lost circulation. Consequently, stopping the test as early as possible after the pressure plot starts to break over is preferred. Formation integrity test (FIT) To avoid breaking down the formation, many operators perform an FIT at the casing seat to determine whether the wellbore will tolerate the maximum mud weight anticipated while drilling the interval. If the casing seat holds pressure that is equivalent to the prescribed mud density, the test is considered successful and drilling resumes. When an operator chooses to perform an LOT or an FIT, if the test fails, some remediation effort typically a cement squeeze should be carried out before drilling resumes to ensure that the wellbore is competent. Remedial measures A lost-circulation incident exacts a heavy cost that goes far beyond the price of products that are used to treat it. Lost circulation causes nonproductive time that includes the cost of rig time and all the services that support the drilling operation. Losing mud into the oil or gas reservoir can drastically reduce (or eliminate) the operator’s ability to produce the zone. Prevention is critical, but, because lost circulation is such a common occurrence, effective methods of remediation are also a high priority. When lost circulation occurs, sealing the zone is necessary unless the geological conditions allow blind drilling, which is unlikely in most cases. The common LCMs that generally are mixed with the mud to seal loss zones may be grouped as:  

Fibrous Flaked  Granular  A combination of fibrous, flaked, and granular materials These materials are available in course, medium, and fine grades for an attempt to seal low-tomoderate lost-circulation zones. In the case of severe lost circulations, the use of various plugs to seal the zone becomes mandatory. It is important to know the location of the lost-circulation zone before setting a plug. Various types of plugs used throughout the industry include:  

Bentonite/diesel-oil squeeze Cement/bentonite/diesel-oil squeeze

 

Cement Barite Squeeze refers to forcing fluid into the lost-circulation zone. Use of loss of circulation materials Rock mechanics and hydraulic-fracture theory indicate that it is easier to prevent fracture propagation than it is to plug the fracture later to prevent fluid from re-entering.[1] Because of the high cost of most weighted, treated drilling-fluid systems, LCM routinely is carried in the active system on many operations in which probable lost-circulation zones exist, such as: “Rubble” zones beneath salt or in a known depleted zone Natural and induced fractures Formations with high permeability and/or high porosity Vugular formations (e.g., limestone and chalk) Using an LCM that can be carried in the drilling fluid without significantly affecting its rheology or fluid-loss characteristics facilitates the preventive pretreatment. Pretreatment can mitigate wellbore breathing (ballooning), seepage losses, and/or potential lost circulation when drilling depleted zones.    

When a loss zone is encountered, the top priority is keeping the hole full so the hydrostatic pressure does not fall below formation pressure and allow a kick to occur. The hydrostatic pressure may be purposely reduced to stop the loss, as long as sufficient density is maintained to prevent well-control problems. Loss zones also pose a high risk of differential sticking. Rotating and reciprocating the drillstring helps reduce this risk while an LCM treatment is prepared. If the location of the loss zone is known, it might be advisable to pull the drillstring to a location above the affected area. A variety of LCM is available, and combining several types and particle sizes for treatment purposes is common practice. Conventional—and relatively inexpensive—materials include:  

Sized calcium carbonate Paper  Cottonseed hulls  Nutshells  Mica  Cellophane Because lost circulation always has been one of the most costly issues facing the industry, a focus on healing the loss zone quickly and safely encouraged the development of proprietary materials that conform to the fracture to seal off pores, regardless of changes in annular pressure. In some cases, such deformable, expanding LCM is pumped ahead of cement jobs in which losses are expected. This type of material has a comparatively high success rate for the prevention and remediation of severe losses. Severe lost-circulation problems that do not respond to conventional treatments might be curable by spotting a hydra table LCM pill, and holding it under gentle squeeze pressure for a

predetermined period. At downhole temperatures, the LCM pill expands rapidly to fill and bridge fractures, allowing drilling and cementing operations to resume quickly, sometimes in 4 hours or less. Alternatively, rapid-set LCM products are available that react quickly with the drilling fluid after being spotted across the loss zone and form a dense, flexible plug that fills the fracture and adheres to the wellbore. In some cases, this type of plug has proved so effective that the natural fracture gradient of the formation actually increased, allowing the operator to resume drilling and increase the mud weight beyond constraints established before the treatment.

Control operations - With heavy mud A non-standard well control method is to attempt to bring the well under control by circulating heavy mud to overbalance the surface pressures. The theory behind this method is that the well can then be opened and the string run deeper. This method is not reliable since there is no proper control of bottom hole pressures during circulation, nor during running the string back to bottom. Pumping a Slug of Heavy Mud Pumping a slug of heavy mud often carried out to enable the pipe to be pulled dry and the hole to be more accurately monitored during the trip. The following equation is used to calculate the dry pipe volume for the slug pumped: Dry Pipe Volume = Slug Volume x (Slug Weight ÷ Mud Weight – 1) This dry pipe volume can be converted to Dry Pipe Length by dividing this volume by the internal capacity of the pipe as illustrated in the following equation: Dry Pipe Length = Dry Pipe Volume (bbls) ÷ Drill Pipe Capacity (bbls/ft)

Control operations - With barite plug A plug made from barite weighting materials that is placed at the bottom of a wellbore. Unlike a cement plug, the settled solids do not set solid, yet a barite plug can provide effective and lowcost pressure isolation. A barite plug is relatively easy to remove and is often used as a temporary facility for pressure isolation or as a platform enabling the accurate placement of treatments above the plug. A successful Barites plug should accomplish:  

killing of the well Plugging of lost circulation zone. Application Barite plugs shall be applied when the following situations arise:    

Simultaneous kicking and lost circulation. Abandonment procedure to allow safe withdrawal of drillpipe to permit subsequent setting of a cement plug. Withdrawal of drillpipe to either set casing or repair existing casing strings. Plugging of drillpipe in emergency situations.

A barite plug is a slurry of barite in fresh water or diesel oil which is spotted in the hole to form a barite bridge that will seal the flow and allow control of the well to be re-established. The plug is displaced through the drillstring and, if conditions allow, the string is pulled up to a safe point above the plug. The barite settles out rapidly to form an impermeable mass capable of shutting off high rates of flow. The effectiveness of a barite plug derives from the high density and fine particle size of the barite and its ability to form a tough impermeable barrier. A barite plug has the following advantages:    

The slurry has a high density (19.0 - 22.0 ppg) It can be pumped through the bit and offers a reasonable chance of recovering the drillstring The material required is normally available at the rig site. The plug can be drilled easily if required.

The main disadvantages the risk of settling and consequent plugging of the drill string if pumping is stopped before the slurry has been completely displaced. Two types of barite slurries can be used:  

Barite fresh water slurry Barite diesel Oil slurry Other materials can be used if a very high slurry density is required to stop the flow so that the slurry will settle, limonite and galena have been used in the past and micaceous hematite is potentially useful. All of these materials have a higher density than barite. Regardless of the materials used, all slurry formulations should be pilot tested before mixing to ensure settling and dehydration before mixing. Barite Plug - Fresh Water Slurry One Weird Trick to Stay Asleep All Night (peaklife.com) The amount of barite and fresh water required to formulate .1.0 bbl of slurry at various densities is shown in the following table: Required Density (ppg)

Volume of Fresh Water (bbl)

Weight of Barite (lbs)

18

0.642

530

20

0.560

643

21

0.528

695

22

0.490

750

Barite Plug Preparation The mix water is prepared first and barite is added as needed to attain the required slurry density. Equipment needed Cementing unit with high pressure jet in mixing hopper, sufficient clean tankage to store the mix water Mix water preparation Settling Recipe:  1 bbl water (fresh or sea)  15 lb lignosulphate  2 lb/bbl caustic soda (pH = 10.5 to 11.5) Non-settling Recipe:     

1 bbl water (fresh or sea) 15 lb lignosulphate 1 lb XC polymer Defoamer 2 lb/bbl caustic soda (pH = 10.5 to 11.5)

Barite Addition Barite is added to mix water as required to prepare the final slurry. The quantity of barite added is dependent on the final slurry density required. Setting Barite Plug The barite plug will be set and the pipe pulled out of plug following these guidelines:     

Mix and pump slurry with drillpipe as close to bottom as possible. Displace slurry with mud at the same rate Immediately begin pulling pipe Monitor the annulus Trip out of hole after verifying the well is dead.

The barite plug should be pumped and displaced at a rate higher than the kick rate. If the kick rate is unknown a reasonable 5 to 10 bbl/min should be used for the first attempt although very large blowouts can ultimately require kill mud placement at 50 bbls/min. A minimum final plug length of 200 ft and not less than 10 bbls volume should be used to ensure a good seal and allow accurate displacement into the wellbore.

Control operations - With gunk plug A slurry that consists of bentonite, cement or polymers mixed into an oil; bentonite in diesel oil is commonly used as a gunk plug. A small batch of the slurry is pumped down a well that has lost circulation to seal the leaky zone. The gunk plug may or may not be squeezed by pressure into the zone. Water downhole interacts with the bentonite, cement or polymers to make a sticky gunk.

Blowout Preventer (BOP) A large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation. BOPs come in a variety of styles, sizes and pressure ratings. Some can effectively close over an open wellbore, some are designed to seal around tubular components in the well (drillpipe, casing or tubing) and others are fitted with hardened steel shearing surfaces that can actually cut through drillpipe. Since BOPs are critically important to the safety of the crew, the rig and the wellbore itself, BOPs are inspected, tested and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type and legal requirements. BOP tests vary from daily function testing on critical wells to monthly or less frequent testing on wells thought to have low probability of well control problems.

Annular Preventers Annular preventers are the most versatile well control equipment and there are many names referring it as bag preventers, or spherical preventers. The annular preventers are able to seal around several size of drill pipe/drill collar, work string, wireline, tubing, etc. There are some models which can utilize wellbore pressure to provide additional sealing capability. The annular preventer consists of a body, a cap, a piston and a rubber packing element. The illustration below demonstrates the drawing of an annular preventer.

How the annular preventers work? Close - When the hydraulic oil is pumped into the extend port, the element inside will be lifted and squeezed the pipe/tubular.

Open - On the other hand, if the hydraulic fluid is pumped into the retract port, the element will be pushed down resulting in releasing the tubular.

Nowadays, there are several manufactures providing this equipment such as Hydril, NOV (Shaffer) and Cameron. The models available in the market based on the manufactures are listed below: Hydril – Hydril GL, GX, GK and Annu-Flex

Hydril GL

Hydril GK

Hydril Gx

Hydril Anuflex

Cameron – Cameron DL

NOV (Shaffer) – SPHERICAL BOPS

SPHERICAL BOPS In the market, the annular preventers have wide range of size and operating pressure and you can see from the technical specification from the link that we provide. It is very important that personnel must know how to operate and maintenance the annular preventers properly. Personnel must strictly follow the operating manual to prevent the premature failure.

Ram Preventers This preventer consists of two rams which extend into the center of the wellbore in order to shut the well in (see the image below). The ram preventers can be hydraulically or manually operated. When people would like to shut the well in using the ram preventer, they will go to the hydraulic option first. If the hydraulic is not properly operated, the manual system will be utilized.

In order to provide the wellbore sealing, the rams must compose of top seals and packers which are made of the special elastomer. For more understanding, please take a look at the diagram of Cameron BOP below.

(Courtesy of Cameron) When the well is shut in, the packer will seal around drillstring or tubular and the top seal will be pushed against the BOP body. With both top seals and packer, the well is securely shut in when In the drilling industry, there are four types of rams preventers which are Pipe Rams, Variable Bore Rams (VBR), blind rams and blind-shear rams. Pipe Rams – it closes around the drill string or tubular in order to restrict the flow. The size of the rams must match with drill string size in order to properly shut the well in. The rams are designed to hold pressure from the bottom only. Personnel should not close the ram in tool joint or open hole (closing without pipe in the well)

(Pipe Rams – Courtesy of Cameron) Variable Bore Rams (VBR) – It is similar to the pipe rams but it can use with a wider range of outside diameter of pipe. You can see that the packer can be varied depending the force push against the rams. Please see the image below for more understanding.

(Variable Bore Rams (VBR) – Courtesy of Cameron)

Blind Rams – This rams are used to close the wellbore when there is no drilling string in the wellbore and the blind rams cannot shear the pipe. Most operators and drilling contractors don’t consider using this rams but they prefer blind-shear rams because the blind-shear rams can cut the pipe.

Blind Shear Rams – The blind shear rams have two applications – 1 seal the wellbore without pipe in the wellbore, 2 cut the pipe prior to shutting the well in.

(Blind Shear Rams – Courtesy of Cameron)

BOP Stack Organization and BOP Stack Arrangement Blow out Preventer (BOP) is a very important part of well control equipment and the first thing which we would like to discuss in this article is the BOP stack organization. The BOP stack can be configured in various configurations which must be suitable for the operation. API has the recommended component codes for BOP as listed below: A = Annular Preventer G = Rotating Head R = single ram type preventer with one set of rams, blind or pipe. Rd = double ram type preventer with two sets of rams, blind or pipe. Rt = triple ram type preventer with three sets of rams, blind or pipe. CH = high remotely operated connector attaching well head or preventers CL = low pressure remotely operated connector attaching; the marine riser to the BOP S = spool with side outlet for choke and kill lines M = 1000 psi How can I know the BOP configuration and rating from the codes?

When you see the code, you need to read upwards from the bottom of BOP stack. Let’s take a look at the following example: 15M 13-5/8” – RSRRA This BOP stacks has pressure rating of 15,000 psi with a bore size of 13-5/8” inch. There are following BOP component from bottom to top Rams – Spool – Rams – Rams – Annular (see the figure below)

You need to keep in mind that the BOP stack is able to shut the well in and allow you to perform well control operations with the greatest flexibility. Considerations of how to arrange the BOP stack are as follows: • The BOP stack must be suitable for the drilling operation. • The stack should be able to serve the stripping operation not just only shut the well in. • Pressure rating must be higher than expected surface pressure on surface when the well control situation is happened. • Excessive BOP rams cause difficulty to handle and maintenance. Additionally, the cost of BOP stack is more expensive. • Sour gas and temperature on surface directly affects the element in the BOP’s. • The best BOP stack arrangement is the one that is suite for the operation within safety limit. Blow-out Preventers Stack Arrangements: Depending on expected pressures, a combination of one annular preventer, one or more ram-type preventers and a drilling spool can be used as wellhead control equipment. API1 recommends the use of a single designation to distinguish various BOP’s stack arrangements. The designation uses the working pressure of the stack, the through-bore of the preventers and the type of arrangements. Thus, a stack designated as 3M-135/8

-SRA means that the related pressure is 3000 psi (1M=1000psia) , the through-bore is 135/8in and an 97arrangement of one drilling spool (S), one ram type preventer (R) and one annular preventer (A) is used. A drilling spool is normally used as a crossover spool between the BOP and the casing housing. Typical blow-out preventer arrangements for 2 M (2000psi) to 13 M (13000psi) working pressures are given in fig. The BOP’s Control System: The BOP’s are designed to be closed remotely using hydraulic pressure supplied by an operating or control unit. The control unit is designed to close and open each individual BOP through a system of piping and remotely controlled valves. The control unit is normally built on a skidmounted assembly and placed at a safe distance from the rig floor. The main components of a control system include: a-) an accumulator bank; b-) charging pumps; c-) fluid reservoir; d-) a manifold and piping for directing the fluid to the appropriate preventer. Either the rig generators or separate power source can power the pumps. A separate power source is normally used, to allow the unit to be used even when the rig engines are shut down. The prime function of the control system is to store energy which can be released within 30 s or less. This energy is used to close the BOP’s. The rigs air-operated pumps or any manually operated pump can be used to effect the closing 98of the preventers, but these devices are very slow-acting and used as a back-up to the main accumulator pumps. Accumulators: The heart of the operating system is the bank of accumulators. An accumulator is a high-pressure cylinder containing pre-charged nitrogen gas and hydraulic fluid. The gas is a separated from the fluid by a rubber diaphragm or a float. The hydraulic fluid can be just water or hydraulic oil with anti-corrosion additives. Air-operated or electrical pumps are used to force hydraulic fluid from a reservoir into the bank of accumulators until the working pressure of the system is achieved. For example, the working pressure required to close an annular preventer is 1500 psi. Entry of the hydraulic fluid into the accumulator causes the nitrogen gas to occupy a much smaller volume and in turn, have a much higher pressure. The increased gas pressure will help in releasing the fluid at a much faster rate than can be achieved by most pumps, thereby allowing the preventers to be closed quickly. The accumulator is provided with a valve on the outlet connection, which closes when the useable fluid charge is exhausted. This is required to preserve the precharge nitrogen gas. The useable fluid charge is normally 2/3 of the total fluid charge, and is defined as the amount of fluid which can be recovered as the total pressure in the accumulator drops from the 99working pressure to 1200psi. The 1200psi represents the pressure required to hold annular preventer closed.

Charging Pumps: Charging pumps can be air- or electrically driven and are normally powered by two independent sources. An air compressor or an air storage tank can supply the air power. A separate generator is required to provide the electric power. Fluid Reservoir: The fluid reservoir contains the hydraulic fluid used to charge the accumulators and acts to receive the total hydraulic fluid upon opening the preventers. The total capacity of the reservoir should at least be equal to twice the useable fluid capacity of the accumulator system. Hydraulic oil or fresh water-soluble oils are normally used with glycol as an additive when wor Manifold and Piping: Each preventer is provided with 2 lines, an opening and a closing line and a four-way valve. The lines are made of seamless steel with a working pressure equal to or greater than the working pressure rating of the BOP’s stack up to 5000psi.

Advantages and disadvantages of various arrangements Criteria for selection of appropriate arrangement Choke manifold A set of high-pressure valves and associated piping that usually includes at least two adjustable chokes, arranged such that one adjustable choke may be isolated and taken out of service for repair and refurbishment while well flow is directed through the other one.

Choke line A high-pressure pipe leading from an outlet on the BOP stack to the backpressure choke and associated manifold. During well-control operations, the fluid under pressure in the wellbore flows out of the well through the choke line to the choke, reducing the fluid pressure to atmospheric pressure. In floating offshore operations, the choke and kill lines exit the subsea BOP stack and then run along the outside of the drilling riser to the surface. The volumetric and frictional effects of these long choke and kill lines must be considered to control the well properly. Choke Manifold Control Console Choke manifold control console as a control assembly in hydraulic choke manifold, can remote control the open / close of hydraulic choke valve for a long distance and the control panel can indicate the stand-pipe pressure, casing pressure and the opening / closing condition of hydraulic choke valve as well as the pulse number and frequency of the mud pump if pump-pulse counter equipped, which can keep the pressure under well and is a necessary device to control kick and blowout and perform the pressure control technology in oil /gas well.

Technology Parameter (1) Gas-source Pressure: 100psi (3) Working Pressure: 500psi (5) Quick Nipple in oil line: M22 x 1.5 (7) Length x Width x High: 960 x 600 x 1300

(2) Ambient Temperature: -20℃ ～ +60℃ (4) Quick Nipple in gas line: M16 x 1.5 (6) Hydraulic oil: anti-cryogenic hyd oil (8) Weight: 300Kg

Standpipe Manifold 1. Vertical structure: could stand on deck with smaller occupation. 2. Proper match: it is assembly of choke manifold and two sets of kill line, fabricated with two layers of drilling floor for easy operation. 3. Full function: available with full function of the horizontal model manifold. The hard supporting frame is totally enclosed and corrosion prevention. 4. Easy assembly: it is designed to combination with four components for ease of transportation.

Kill Manifold 1. Application In case of increase in well head pressure, the kill manifold can provide a means of pumping heavy drilling fluid into the well to balance bottom hole pressure so that well kick and blowout can be prevented. In this case, by using blow down lines connected to the kill manifold, the increasing well head pressure also can be released directly for bottom hole pressure release, or water and extinguishing agent can be injected into the well by means of the kill manifold. The

check valves on the kill manifold only allow injection of kill fluid or other fluids into the well bore through themselves, but do not allow any backflow so as to perform the kill operation or other operations. 2. Structure The kill manifold consists of check valves, gate vales, pressure gauges and pipelines. The one end of the kill manifold is connected to the drilling spool and the other end is connected to the pump. The kill manifold and choke manifold are both designed to API 16C and can be used together. The kill manifold is available from 14MPa, 21MPa, 35MPa and 70MPa pressure ratings. 3. Operating Requirements (1) Working pressure of all pipelines, gate valves and check valves shall be compatible with that of the BOP stack used. (2) The kill manifold is not intended to be used as common lines for pouring drilling fluid.

Choke Manifold 1. Application Choke manifold is necessary device to control the well kick successfully and execute the pressure control technology on oil/gas well in the course of drilling, as it is, the device is adopted to execute new drilling-well’s technique of balance pressure, which can prevent the pollution of oil-layer, improve the speed of drilling and control blowout effectively. One end of the device connects with the side flange of BOP spool. When BOP closes, it can control the finite pressure from casing by adjusting the choke valve’s opening, so balanced drilling can work under minimum pressure-difference. 2. Assembly & structure Choke manifold consists of choke valve, gate valve, pipeline, fittings and pressure gauge etc. 3. Working principle: When the pressure rising in well, fluid in well can be released in utilization of the choke valve opening/closing in choke manifold to control casing pressure, which can directly blow out through gate valve as the casing pressure is quite high. 4. Specification: Pressure level is divided into five levels, i.e. 2,000psi, 3,000psi, 5,000psi, 10,000psi, 15,000psi; it can be designed according to the requirement of customer.

5. Operation requirement (1) all the working pressures of parts in choke manifold should be matched with the working pressure of the BOP stack used. (2)Choke manifold should be installed at the place where operator approach it conveniently, pressure test should be executed as installation, while the sealing test pressure should equal to the rated working pressure; (3)Pipeline should be so smooth and straight as possible, the corner of the pipeline should be made of 120°shaped forged steel bent pipe, which should have adequately large bore. (4)The working pressure gauge should be installed. (5) In winter, the choke manifold be able to work under a low temp condition.

Fabrication of choke manifold is according to the requirements of API spec 16C. Working pressure: 2,000psi - 15,000psi Nominal bore size: 2.1/16” to 4.1/16”

Tripping Procedures Tripping in or out of the well must be maintained using an accurate log called a trip sheet. A trip sheet is used to record the volume of mud put into the well or displaced from the well when tripping. A calibrated trip tank is normally used for the accurate measurement of mud volumes and changes to mud volumes while tripping.

When tripping pipe or drill collars out of the hole, a given volume of mud is put into the well for the volume of steel removed. If the volume required to fill the hole is significantly less than the volume of steel removed, then tripping must be stopped to ensure the well is stable, and consideration given to going back to bottom to condition the mud and investigate the cause of the problem.

Driller’s Method Vs Wait and Weight The two widely used constant bottomhole circulating methods are the Driller’s Method and the Wait and Weight (W&W) Method. Well control experts are often strongly opinionated on selecting the better method to circulate an influx out of the wellbore. The purpose of this article is to highlight the major advantages and disadvantages of the two methods. The basic principle of both methods is to keep bottomhole pressure (BHP) constant at or, preferably, slightly above the formation pressure. The Driller’s Method requires two circulations. During the first circulation, the influx is circulated out with the original mud weight. Constant BHP is maintained by holding circulating drill pipe pressure constant through the first circulation. If the original mud weight is insufficient to balance the formation pressure, the well is killed by circulating a heavier mud (kill mud) in a second circulation. To hold constant BHP during the second circulation, one of two procedures is employed. Casing pressure is held constant while pumping kill mud from surface to bit, and drill pipe pressure is held constant thereafter until kill mud is observed returning to the surface. Alternately, during second circulation, a drill pipe pressure schedule can be calculated and followed while pumping kill mud from surface to bit, and drill pipe pressure is held constant thereafter. The W&W Method involves only one circulation. The influx is circulated out, and the kill mud is pumped in one circulation. While pumping kill mud from surface to bit, a drill pipe pressure schedule has to be calculated and followed. The drill pipe pressure is held constant thereafter until kill mud is observed returning to the surface. The W&W Method is sometimes called the Engineer’s Method because it involves more calculations compared with the Driller’s Method. There is a widespread misconception that the Driller’s Method is preferred only because it is simple. We will discuss various reasons why the Driller’s Method could be better for circulating an influx in many or even most wells drilled. Any drilling organization or company can adopt a policy of recommending just one well control method so that everybody in the organization can be competent in at least one method. This may help in avoiding confusion in the field and promote understanding of how to efficiently circulate a kick out of the wellbore without creating major well control problems. There is a shortage of experienced personnel in the drilling industry, and ensuring competency in one method could lead to fewer disasters. We have to keep in mind, however, that even experienced personnel do not routinely kill wells. They may kill only a few wells in their entire

career. We can achieve operational excellence by ensuring their competence in one method. It may be better to use a good method expertly than a slightly better method inexpertly. COMPARISON We will compare the advantages and disadvantages of the two methods under specific conditions. The different applications are various types of wells and their geometry. Deviated hole / tapered drill string: The drill pipe pressure schedule for the W&W Method is fairly simple to calculate if the wellbore is vertical and there is one size of drill pipe. The schedule becomes complicated and difficult for rig personnel in complex deviated well geometries and/or with multiple sizes of drill pipe. If the proper drill pipe pressure schedule is not calculated while performing the W&W Method, BHP pressure may not be held constant. Figure 1 shows two drill pipe pressure schedules for a horizontal well. The first schedule does not compensate for the hole deviation while the second one does. As per this example, if we do not compensate for hole deviation, we will have approximately a 200-psi overbalance when the kill mud gets to the end of build inside the drill string. This overbalance of 200 psi could be detrimental to weak formations and could increase shoe and surface pressures. One often-mentioned advantages of the W&W Method is lower pressure at the casing shoe. But if a proper schedule is not calculated for the W&W Method, we may expose the casing shoe or weak formations to higher pressures compared with the Driller’s Method. Hole problems: Many wells are drilled in areas with significant hole instability problems. If the drill string is kept static with no mud circulation, the drill string may get stuck in the hole due to pack-off problems. If it is decided to kill the well with the W&W Method, kill mud may have to be mixed before circulation can be established. This long period of non-circulation with little or no pipe movement may not be desirable in problematic hole sections. The Driller’s Method has some obvious advantages under these circumstances. Circulation can be started as soon as a stabilized shut-in casing pressure (SICP) and shut-in drill pipe pressure (SIDPP) are established. The first circulation of the Driller’s Method is done with the original mud in the hole. If the method is understood and followed correctly, non-circulating time in the well is minimized, and any further hole problems may be minimized. Fluid mixing capability of rigs: While we are building new rigs and modifying existing ones to drill wells more efficiently, a vast majority of wells are still drilled all over the world using older rigs with limited capabilities. Kill-weight mud may not be quickly prepared and/or pumped at a desired rate if the W&W Method is employed. The Driller’s Method may be preferred under these circumstances to avoid excessive increase in surface and shoe pressures due to gas migration. We acknowledge that on some rigs, kill mud can be mixed at a fast rate without problem. But simultaneous mixing and pumping of kill mud may make pit volume gain and loss difficult to track and lead to confusion, particularly in the event of complications.

Drilling in formations with ballooning potential: Ballooning is a phenomenon occasionally encountered in some formations. Ballooning can be defined as flowback from the well after shutting the pumps off, which is preceded by losses while the pumps were running. Losses in the well can be attributed to extra BHP due to equivalent circulation density (ECD). After the pumps are shut down, the ECD does not exist anymore, resulting in a drop in BHP, and mud is forced back into the wellbore. It appears the well is flowing and is referred to as ballooning. Ballooning is often misinterpreted as a kick. If it is decided to kill the well with the W&W Method, mud weight may be increased due to incorrect measurement of formation pressure. Due to the additional mud weight, BHP increases even further. This can induce more losses and worsen the ballooning problem. For the above reasons, it is commonly recommended that the Driller’s Method be followed in ballooning formations. Since the Driller’s Method does not require any increase in mud weight during the first circulation, no additional BHP is exerted on the formation. After the first circulation of the Driller’s Method, the situation can be assessed and further course of action can be decided (i.e., drilling ahead with no mud weight increase if ballooning continues). Complications and friction changes during well control: While a well is being killed, complications may occur during the process. When killing a well with the W&W Method, if one or more of the bit nozzles plug while drill pipe pressure schedule is followed, the pressure schedule must be recalculated immediately. The failure to notice the change and to recalculate the proper drill pipe pressure schedule may result in underbalance. On-the-spot recalculation of the drill pipe pressure schedule may be difficult for highly deviated wells and/or with tapered drill strings. Furthermore, when a kick is taken, it is normal that the rig crew become nervous. If any complications arise while killing the well, rig personnel may panic and make poor decisions. If the kick is circulated with the Driller’s Method and one or more of the bit nozzles plug, the response by the choke operator is fairly simple. The circulating drill pipe pressure should be allowed to increase while temporarily holding casing pressure constant (as during start-up). After the drill pipe pressure stabilizes, the new circulating pressure should be held constant during the rest of the first circulation. If one or more nozzles plug during the second circulation of the Driller’s Method while pumping kill mud from surface to bit, the simple response is to continue holding casing pressure constant until kill-weight mud is at the bit and then switch to hold whatever drill pipe pressure is shown on the pump gauge. Hence, if complications arise during well kill operations, it is easier to respond with the Driller’s Method. Deepwater wells: If gas kicks are taken in deepwater wells, there is a possibility of hydrate formation in the BOPs or choke/kill lines. The high-pressure and low-temperature conditions in deepwater are ideal for formation of hydrates when free water comes into contact with gas. Possible long periods of non-circulation with the W&W Method will make conditions more favorable for hydrate formation due to cooling of mud. Hence, non-circulating times in

deepwater wells with a gas influx should be minimized. By establishing circulation as soon as possible with the Driller’s Method, the mud can be kept warm, and hydrate formation may be prevented. Time to kill well: The W&W Method involves only one circulation while the Driller’s Method involves two circulations. This sounds as if we can always save time by following the W&W Method. But other factors need to consider. If the time required to mix kill mud is significant, we may not save any time with the W&W Method. We may not be able to circulate all the influx out with just one circulation due to hole conditions, such as gas remaining in the high pockets of the well, poor hole cleaning and bad mud properties. Additional circulations are almost always required for complete removal of the influx and the addition of safety factors in the mud weight. Therefore, the time element may not be significant, and most experts agree that doing it right is more important than doing it faster. Shoe Pressure: Maximum shoe pressure often occurs when the top of a gas influx is at the casing shoe. Pressure at the shoe can be lower with the W&W Method if kill mud gets into the annulus before the top of the bubble is at the shoe. But, for this to happen, the first criteria is that the drill string volume has to be less than the open-hole volume minus the bubble size at the shoe. If the drill string volume is more than the open-hole volume minus the bubble size at the shoe, then lower shoe pressure cannot occur with the W&W Method. We also have to consider gas migration issues before determining whether the W&W Method will have an advantage over the Driller’s Method with respect to maximum shoe pressures. There may be a significant amount of wait time to mix kill mud. During this time, gas may be migrating. Most methods used to control BHP before pumping involves application of a surface pressure safety factor. These can easily exceed the expected benefit that the early delivery of killweight mud to the open-hole annulus is intended to provide. There is an often a good chance that a kick is not detected when the kick is at bottom. Many times, we may circulate or continue drilling with the influx before it is detected. At times, the gas may already be above the shoe due to delayed detection and gas migration, even before we start pumping kill mud. Synthetic/oil-base mud (SOBM) is now routinely used to drill wells. Unlike in water-base mud (WBM), gas is soluble in SOBM. Kick detection with SOBM is not as simple as with WBM. The size and time of the kick may not be easily determined. Gas may stay in solution in SOBM, and the influx may not be detected until the gas is close to surface, often well above the shoe. Due to the above reasons, only rarely can lower shoe pressures be achieved with the W&W Method compared with the Driller’s Method. Only if all conditions are favorable will the W&W Method give us lower shoe pressures. Realistically, the chances are minimal and the magnitude of this effect is usually insignificant. Figure 2 shows a vertical well with a long open-hole section to create conditions likely to favor the W&W Method. The hole configuration has been kept fairly simple, and we have considered a big influx of gas that expands to 1,500 ft just below the shoe for both methods. If we follow the

W&W Method, as we can see from the calculation shown in the appendix, we achieve a maximum pressure reduction at the shoe of 111 psi. The reduction of 111 psi in the shoe pressure will only exist when the influx is detected by the rig crew when the gas is at the bottom and the influx stays at the bottom without any migration while mixing kill mud (or is handled perfectly with volumetric control and no safety factors/working pressure margins). We do not have to be an expert to realize that these conditions will probably not exist in any wellbore. Hence, even in the relatively extreme scenario like this, a 111-psi reduction in shoe pressure with the W&W Method is almost impossible to achieve. In many wells, we may not get any reduction in shoe pressures, and even if we get some reduction in pressures, it is probably not worth taking other risks with the W&W Method. Maximum casing pressure at surface (PcMax) and peak gas flow rate: Maximum casing pressure during the circulation is observed when the top of the gas bubble gets to surface. This may be defined as PcMax. The gas flow rate through the mud gas separator is maximum at the same time when PcMax is observed. Peak Gas Flow Rate must not exceed the gas-handling capacity of the mud-gas separator. PcMax and peak gas flow rate will be lower with the W&W Method if kill mud gets into the annulus before the top of the bubble gets to surface. If the W&W Method is followed, there is a good chance that kill mud will enter the annulus before the top of the bubble gets to surface, and we will likely have lower surface pressures compared with the Driller’s Method. Lower PcMax may be an advantage for the W&W Method when we drill HPHT wells where surface pressures could be a concern. The surface equipment may be exposed to high pressures and gas flow rates for a long time during well-killing operations in these wells. However, for most of the regular wells we drill, PcMax and peak gas flow rates may not be a primary concern. In the examples in Figure 3, we calculate PcMax for kicks taken while drilling a regular well and an HPHT well. The large kicks modeled here have been selected to simulate worse-case scenarios. The PcMax calculation is explained in the Appendix. As can be seen for the regular well example, the difference in PcMax is not significant between the Driller’s and W&W methods. Even in case of a large kick in the HPHT well, the difference in surface pressures is only 335 psi. CONCLUSION The Driller’s Method does offer some distinct advantages over the W&W Method. The W&W Method may be advantageous to achieve lower shoe and surface pressures in some cases. However, these advantages are often exaggerated and, in reality, we may not see a significant reduction in maximum shoe and surface pressures. Due to gas migration and hole geometry, many times shoe pressure may not be lower at all with the W&W Method. Application of the W&W Method may even give us higher shoe pressures if the drill pipe pressure schedule is not calculated and followed properly. Reduction in PcMax may not be significant even in deep HPHT wells.

The W&W Method may be difficult to follow properly in complex, deviated wells and/or with tapered drill strings. The Driller’s Method is a preferred method when hole problems are significant and any long non-circulation times could further compound the problems. Hydrates concern in deepwater wells may require limiting non-circulation times with possible gas influx in the well Due to the low experience level of current drilling personnel, limited field practice with well control methods by a majority of experienced personnel, exaggerated and often unachievable benefits, the W&W Method may not offer significant advantages. Additionally, certain conditions — ballooning, swabbed kicks, hydrate concerns in deepwater and hole stability problems — may dictate using only the Driller’s Method. Due to all these reasons, the Driller’s Method is a logical, simple, practical, adequate and often superior approach to kill majority of the wells we drill.

Appendix: Shoe pressure reduction with the W&W Method compared with the Driller’s Method: Height of Kill Mud in the Annulus When Top of the Gas Is at the Casing Shoe = (Open-Hole Volume – Drill String Volume – Gas volume at shoe) / Annulus Capacity Pressure Reduction with the W&W Method = Height of Kill Mud in the Annulus * 0.052 * (Kill Mud Weight – Original Mud Weight) Calculation of PcMax in the Driller’s Method: PcMax = O + Q O = SIDPP / 2 Q = (O2 + K*M*N*P)1/2 K = Reservoir Pressure M = Initial Pit Volume Increase / Annulus Capacity Factor in bbls/ft Right Below Wellhead N = Difference in Mud Weight Gradient and Influx Gradient = MW*0.052 – Influx Gradient P = Temperature and Compressibility Correction Factor (TZ) = 4.03-(0.38 * ln(K) Calculation of PcMax in the W&W Method: PcMax = U + V U = 0.052* G*Q / 2 / R V = (U2 + K*M*N*P)1/2 G = SIDPP / 0.052 / TVD Q = Drill String Capacity in bbls/ft R = Annulus capacity factor in bbls/ft right below wellhead K = Reservoir Pressure

M = Initial Pit Volume Increase / Annulus Capacity Factor in bbls/ft Right below Wellhead P = TZ = Temperature and Compressibility Correction Factor = 4.03-(0.38 * ln (K)) N = Difference in Mud Weight Gradient and Influx Gradient = MW*0.052 – Influx Gradient