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Applied Drilling engineering for oil and gas Delivered by Eng Musenze Lastone; BSc. in oil and gas Prodn. (kyu), COURSE CONTENT  Introduction  Rig Components  Drill string  Drill Bits  The Subsurface Environments (Formation Temperature and Pressures)  Drilling Fluids  Well Control  Casing  Cementing Well Control Basic Terms Used Well control - refers to the control of downhole formation pressures penetrated by the well. Formation pressure - the pressure in the pore space of the formations being drilled. Borehole pressure - the hydrostatic pressure exerted by the column of mud in the wellbore.It is essential that the borehole pressure, due to the column of fluid, exceeds the formation pressure at all times during drilling. Kick - an influx of fluid into the borehole. Blowout - the drilling mud is pushed out of the borehole and the formation fluids flow in an uncontrolled manner at surface. BOP - equipment used to close off the well at surface with valves. Primary Control - The control of the formation pressure by ensuring that the borehole pressure is greater than the formation pressure. Secondary Control - The control of the formation pressure by closing off the BOP valves at surface.

Pressure Gradients OVERBURDEN STRESS Mud Hydrostatic Pressure Formation Pore Fluid Pressure Fracture Pressure

Pressure Gradients Overburden;  The pressure exerted, at a given depth, by the accumulated weight of overlying sediments.  It is therefore a function of both rock matrix and pore fluid Formation Pressure  The pressure exerted by the fluid contained in the pore spaces of rocks.  It is equivalent to the normal hydrostatic pressure of the regional formation fluid; the pressure exerted by the vertical column of formation fluid(s).

Pressure Gradients Fracture Pressure • The maximum pressure a formation can sustain without failure occurring. The weakest plane of formations is typically horizontal.Mud Hydrostatic Pressure • The pressure exerted by the weight of a vertical column of static drilling fluid or mud

Pressure Gradients Equivalent Circulating Density • Increase in bottom hole pressure (BHP) through frictional pressure losses resulting from mud circulation • ECD (emw) = MW + annular pressure loss (emw)

Swab Pressure • Reduction in annular pressure caused by frictional pressure loss when the drill string is lifted • Leads to influx and possible kick, if the annular pressure is reduced below the formation pressure

Pressure Gradients Surge Pressure • Increase in annular pressure caused by frictional pressure loss when the drill string is run in hole. • Leads to formation breakdown if surge pressure exceeds the fracture gradient; resulting in lost circulation and possible kick orblowout.

Pressure Gradients If Pform exceeds annular pressure>>>KICK If annular pressure exceeds Pfrac>>>FRACTURE
 * 1) Vertical Depth Pressure
 * 2) Overburden (OBG)
 * 3) Fracture (Pfrac)
 * 4) Mud Hydrostatic
 * 5) Formation (Pform)
 * 6) ECD

Balancing Pressures Mud weight must therefore be selected to balance the formation pressure and prevent a kick…..but it cannot be so high that it would cause a shallower formation to fracture. This could lead to losing circulation of fluids at the shallower depth, while kicking from a deeper formation. This is an underground blowout.

Equivalent Mud Weight  The “annular pressure” is key to well balance and control.  Annular pressure is dependent on the mud weight although it can be increased or decreased in certain situations: - o Lifting pipe and swabbing reduces annular pressure o Running pipe, causing surge, increases annular pressure o Circulating increases annular pressure  Therefore, measuring the mud weight at surface is the only way we have of “visualizing” pressures exerted downhole.  Formation related pressures are typically quoted in terms of “equivalent mud weight” (emw).

Density - Pressure conversion  Pressure = Density * TVD * Constant i.e.  Mud Hyd = MW * TVD * g  PSI = ppg * feet * 0.052  KPa = kg/𝒎𝟑  PSI = SG * feet * 0.433 • PSI = pounds per square inch • ppg = pounds per gallon • KPa = kilo Pascals • SG = specific gravity (gm/cc)  ECDemw = MW + Ploss/TVD*g  PPGemw = PPG + PSI/ft*0.052  KPa emw = kg/𝑚3 + KPa /m*0.00981
 * metres * 0.00981

Density - Pressure conversion IMPERIAL  Mudweight = ppg  Pressure Gradient (psi/ft) = ppg * 0.052  Pressure (psi) = ppg * feet * 0.052  Equivalent mudweight (ppg emw) = psi / (feet * 0.052) SI UNITS  Mudweight = kg/m3  Pressure Gradient (kPa/m) = kg/𝒎𝟑 * 0.00981  Pressure (kPa) = kg/𝒎𝟑 * metres * 0.00981  Equiv’t mudweight (kg/𝒎𝟑 emw) = Kpa / (metres * 0.00981)

What is a kick? For a kick to occur:  The formation pressure must exceed the wellbore or annular pressure.  Fluids will always flow in the direction of decreasing or least pressure.  The formation must be permeable to allow the formation fluids to flow.  An influx of formation fluid into the wellbore that can be controlled at surface.

What is a Blowout?  An underground blowout occurs when there is an uncontrollable flow of fluids between formations. In other words, one formation is kicking while, at the same time, another formation is losing circulation.  A surface blowout occurs when the well cannot be shut in to prevent the flow of fluids at surface.  Preventing a kick from becoming a blowout is paramount in well control! Blowouts occur when the flow of formation fluids cannot be controlled at surface.

What is a Blowout? The severe consequences of a blow-out:  Loss of human life  Loss of rig and equipment  Loss of reservoir fluids  Damage to the environment  Huge cost of bringing the well under control again.

Typical Causes of Kicks  Not keeping the hole full when tripping out of hole • If mud is not pumped into the hole to replace the steel volume removed, the mud level in the hole will drop reducing the overall mud hydrostatic. • Critical process when pulling drill collars  Reducing annular pressure through swabbing • Frictional forces, when lifting pipe, reduces the annular pressure • Most critical at the beginning of a trip when the well is balanced by mud hydrostatic and when swab pressures are greatest.  Lost circulation • Leading to drop in mud level and hydrostatic pressure  Excessive ROP when drilling through gaseous sands • Too much gas allowed into the annulus, especially when it starts expanding, could cause a reduction in mud hydrostatic that would allow an influxThe severity of a kick (amount of fluid which enters the wellbore) depends on several factors including the:  Type of formation (sand or shale);  Pressure, the magnitude of the negative pressure differential;  Nature of the influx, oil, gas or salt water. Every operator company will have a policy to deal with pressure control problems. This policy will include training for rig crews, regular testing of BOP equipment, BOP test drills and standard procedures to deal with a kick and a blow-out.

WELL CONTROL PRINCIPLES Primary Control Primary control over the well is maintained by ensuring that the pressure due to the column of mud in the borehole is greater than the pressure in the formations being drilled i.e. maintaining a positive differential pressure or overbalance on the formation pressures. Secondary Control  Secondary control is required when primary control has failed and formation fluids are flowing into the wellbore.  The aim of secondary control is to stop the flow of fluids into the wellbore and eventually allow the influx tobe circulated to surface and safely discharged, while preventing further influx downhole. Secondary Control Secondary Control is the control of the formation pressure by closing off the BOP valves at surface. Tertiary Control Tertiary Control is the control of formation pressure by pumping heavy mud from the surface into the well to stop the influx of formation fluids.

Levels of well control

Primary Control  Primary control can be lost when the formation pressure in a zone which is penetrated is higher than that predicted by the reservoir engineer or geologist.  Apart from that, primary control can be lost when the pressure at the bottom of the well decreases if either the mud density or the height of the column of mud decreases. Reduction in mud weight  The mud weight is generally designed such that the borehole pressure opposite permeable (and in particular hydrocarbon bearing sands) is around 200-300psi greater than the formation pore pressure.  This pressure differential is known as the overbalance.  The mud weight will fall during normal operations because of the following: Solids removal; Excessive dilution of the mud (due to watering back); Gas cutting of the mud.

Reduction in mud weight  Solids removal occurs at the surface with the various equipment put in place like the shale shakers, desanders and desilters.  During this process mud components like barite can also be removed from the mud hence a reduction in the mud weight.

Reduction in mud weight  Excessive dilution of the mud (due to watering back), the aim of watering back is to reduce the weight and solids content of the mud by addition of water, occurs usually prior to mud treatment. Once there is excessive dilution of the mud it becomes a problem.  Gas cutting of mud; This is the contamination of mud by formation gas. It greatly reduces the mud weight. If too much gas is allowed into the annulus, especially as it rises and starts expanding, it will cause a reduction in the annular pressure.

Reduced Height of Mud Column  During normal drilling operations the volume of fluid pumped into the borehole should be equal to the volume of mud returned and when the pumps are stopped the fluid should neither continue to flow from the well nor should the level of the mud fall below the mud flowline.  The mud column height may be reduced by; Tripping, Swabbing and

Lost Circulation. Reduced Height of Mud Column  Tripping is the process of pulling the drill string out of the hole or to run in back.  When pipe is pulled from the hole, mud must be pumped into the hole to replace the steel volume removed.  If not, the mud level in the hole will drop, leading to a reduction in the overall mud hydrostatic pressure.  Keeping the hole full is extremely critical when pulling drill collars owing to the large steel volume. A trip tank is used to measure the amount of fluid required in order to fill the hole when pipe is pulled out and to measure the amount of fluid displaced when pipe is run in.

Reduced Height of Mud Column  Swabbing is a temporary lowering of the hydrostatic head due to pulling pipe out of the hole.  Frictional forces resulting from the mud movement caused by lifting pipe, reduce the annular pressure.  This is most critical at the beginning of a trip when the well is balanced by mud hydrostatic and when swab pressures are greatest.  More than 25% of blowouts result from reduced hydrostatic pressure caused by swabbing.

Reduced Height of Mud Column  Lost Circulation (Lost Returns) is the reduced or total absence of fluid flow up the annulus when fluid is pumped through the drill string.  Lost circulation occurs when the drill bit encounters natural fissures, fractures or caverns, and mud flows into the newly available space.

Reduced Height of Mud Column  Lost circulation may also be caused by applying more mud pressure (that is, drilling overbalanced) on the formation than it is strong enough to withstand, thereby opening up a fracture into which mud flows.  Therefore, if drilling fluid is being lost to a formation, it can lead to drop in mud level in the wellbore and reduced hydrostatic pressure.

Example A well is drilled 8500ft using mud with density of 15ppg. If the formation pore pressure at this depth was 5000psi. a) What would be the mud pressure overbalance? b) If the mud density was 9ppg what would be the overbalance? Solution a) 𝑀𝑢𝑑 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = ℎ𝜌𝑔 = 0.052 × 15 × 8500 = 6630𝑝𝑠𝑖 𝑂𝑣𝑒𝑟𝑏𝑎𝑙𝑎𝑛𝑐𝑒 = 𝑀𝑢𝑑 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 − 𝑃𝑜𝑟𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 6630 − 5000 = 1630𝑝𝑠𝑖 b) 𝑀𝑢𝑑 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = ℎ𝜌𝑔 = 0.052 × 9 × 8500 = 3978𝑝𝑠𝑖 𝑂𝑣𝑒𝑟𝑏𝑎𝑙𝑎𝑛𝑐𝑒 = 𝑀𝑢𝑑 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 − 𝑃𝑜𝑟𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 3978 − 5000 = −1022 (𝑢𝑛𝑑𝑒𝑟𝑏𝑎𝑙𝑎𝑛𝑐𝑒)

Indicators of a kick Primary Indicators Secondary Indicators Flow Rate Increase Cut Mud Weight Pit Volume Increase Drilling Break Flowing Well With Pumps Off String Weight Change Improper Hole Fill-Up on Trips Pump Pressure Decrease and Pump Stroke Increase

Primary Indicator  Flow Rate Increase o An increase in flow rate leaving the well, while pumping at a constant rate, is a primary kick indicator. o The increased flow rate is interpreted as the formation aiding the rig pumps by moving fluid up the annulus and forcing formation fluids into the wellbore.

 Pit Volume Increase o A continual increase in trip tank level clearly shows that a kick is taking place. o Fluids entering the wellbore displace an equal volume of mud at the flowline, resulting in pit gain.

 Flowing Well With Pumps Off o When the rig pumps are not moving the mud, a continued flow from the well indicates a kick is in progress. o An exception is when the mud in the drill pipe is considerably heavier than in the annulus, such as in the case of a slug. o A slug is a heavy viscous quantity of mud which is pumped into the drill string prior to pulling out.

 Improper Hole Fill-Up on Trips o When the drill string is pulled out of the hole, the mud level should decrease by a volume equivalent to the removed steel. o If the hole does not require the calculated volume of mud to bring the mud level back to the surface, it is assumed a kick fluid has entered the hole and partially filled the displacement volume of the drill string.

Secondary Indicators  Cut Mud Weight o Reduced mud weight observed at the flow line has occasionally caused a kick to occur. o There are other causes of reduced mud weight

 Drilling Break o An abrupt increase in bit-penetration rate is called a drilling break. o When the rate suddenly increases, it is assumed that the rock type has changed. o It is assumed that the new rock type has the potential to kick (sand), whereas the previously drilled rock did not have this potential (shale).

Secondary Indicators  Drilling Break o A drilling break shows a new formation has been drilled that may have kick potential. o The drilling break may indicate that a higher-pressure formation has been entered and therefore the chip hold down effect has been reduced and/or that a higher porosity formation (e.g. due to under-compaction and therefore indicative of high pressures) has been entered.

 String Weight Change o Drilling fluid provides a buoyant effect to the drill string and reduces the actual pipe weight supported by the derrick. o Heavier muds have a greater buoyant force than less dense muds. o When a kick occurs, and low-density formation fluids begin to enter the borehole, the buoyant force of the mud system is reduced, and the string weight observed at the surface begins to increase.

 Pump Pressure Decrease and Pump Stroke Increase o Initial fluid entry into the borehole may cause the mud to flocculate and temporarily increase the pump pressure. o As the flow continues, the low-density influx will displace heavier drilling fluids and the pump pressure may begin to decrease. o As the fluid in the annulus becomes less dense, the mud in the drill pipe tends to fall and pump speed may increase. o Other drilling problems may also exhibit these signs. It is proper procedure, however, to check for a kick if these signs are observed.

Precautions to prevent a Kick Precautions Whilst Drilling  During drilling, the drilling crew will be watching for the indicators described earlier  If one of the indicators are seen then an operation known as a flow check is carried out to confirm whether an influx is taking place or not.  The procedure for conducting a flow check is as follows: • Pick up the Kelly until a tool joint appears above the rotary table • Shut down the mud pumps • Set the slips to support the drill string • Observe the flowline and check for flow from the annulus • If the well is flowing, close the BOP. If the well is not flowing resume drilling, checking for further indications of a kick.

Precautions During Tripping  Since most blow-outs actually occur during trips, extra care must be taken during tripping. Before tripping out of the hole the following precautions are recommended: • Circulate bottoms up to ensure that no influx has entered the wellbore • Make a flow check • Displace a heavy slug of mud down the drillstring. This is to prevent the string being pulled wet. The loss of this mud complicates the calculation of drillstring displacement.

Operational procedure following detection of a kick.

SECONDARY CONTROL  This is done using the Blow Out Preventer (BOP)  The aim of secondary control is to stop the flow of fluids into the wellbore and eventually allow the influx to be circulated to surface and safely discharged, while preventing further influx downhole.  Secondary control is required when primary control has failed and formation fluids are flowing into the wellbore.  The 1st step of secondary control is to close the BOP valves, and seal off the drill string to wellhead annulus at the surface.  It is not necessary to close off valves inside the drill pipe since the drill pipe is connected to the mud pumps and therefore the pressure on the drill pipe can be controlled.  Usually it is only necessary to close the annular preventer, but the lower pipe rams can also be used as a back-up if required.  When the well is shut in, the choke should be fully open and then closed slowly so as to prevent sudden pressure surges.  The surface pressure on the drill pipe and the annulus should then be monitored carefully.  These pressures can be used to identify the nature of the influx and calculate the mud weight required to kill the well. Annular preventer Ram preventers Manual closure possible on land rigs and jack ups

SECONDARY CONTROL Shut in Procedure For a kick detected while drilling: i. Raise the kelly above the rotary table until a tool joint appears ii. Stop the mud pumps iii. Close the annular preventer iv. Read shut in drill pipe pressure, annulus pressure and pit gain.

When a kick is detected while tripping: i. Set the top tool joint on slips ii. Install a safety valve (open) on top of the string iii. Close the safety valve and the annular preventer iv. Make up the Kelly v. Open the safety valve vi. Read the shut in pressures and the pit gain. Note: The time taken from detecting the kick to shutting in the well should be about 2 minutes. Regular kick drills should be carried out to improve the rig crew’s reaction time.

Shut-in Pressures  Shut-in pressures are defined as pressures recorded on the drill pipe and on the casing when the well is closed.  The two shut-in pressure are shut-in drill pipe pressure (SIDP) and shut-in casing pressure (SICP).  Assuming a kick at the bottom of the hole, during well control the bottom hole pressure (BHP) must be balanced on both the drill string side and annulus side.  The well can be considered to behave along the lines of a U-tube.  Shut-in pressures are defined as pressures recorded on the drill pipe and on the casing when the well is closed.  The two shut-in pressure are shut-in drill pipe pressure (SIDP) and shut-in casing pressure (SICP). SIDP=0 SICP=0 Drill pipe Annulus BHP = Mud Hydrostatic Pressure SIDP – Shut-in Drill pipe Pressure SICP – Shut-in Casing Pressure BHP – Bottomhole Pressure In a normal drilling situation, the u-tube is open at the surface with the pressure at the bottom of the hole equal to the mud hydrostatic. This pressure would be the same on both sides of the utube, so that the well is balanced.  In case of an influx into the wellbore, the annulus will be partially filled with the formation fluids  Using the u-tube principle we can get the shut-in pressures SIDP Drill pipe Annulus SICP Mud Influx SIDP Drill pipe Annulus SICMud Influx H 𝑭𝒐𝒓𝒎𝒂𝒕𝒊𝒐𝒏 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 = 𝑺𝒉𝒖𝒕 − 𝒊𝒏 𝑫𝒓𝒊𝒍𝒍 𝒑𝒊𝒑𝒆 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 + 𝑴𝒖𝒅 𝑯𝒚𝒅𝒓𝒐𝒔𝒕𝒂𝒕𝒊𝒄 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝑷𝒇𝒐𝒓𝒎 = 𝑺𝑰𝑫𝑷 + 𝑯𝝆𝒎𝒈 𝑬𝒒𝒖𝒂𝒕𝒊𝒐𝒏 𝟏

𝑷𝒇𝒐𝒓𝒎 = 𝑺𝑰𝑪𝑷 + 𝑰𝑵𝑭𝑳𝑼𝑿 𝑯𝒀𝑫𝑹𝑶𝑺𝑻𝑨𝑻𝑰𝑪 𝑷𝑹𝑬𝑺𝑺𝑼𝑹𝑬 + 𝑵𝑬𝑾 𝑴𝑼𝑫 𝑯𝒀𝑫𝑹𝑶𝑺𝑻𝑨𝑻𝑰𝑪 𝑷𝒇𝒐𝒓𝒎 = 𝑺𝑰𝑪𝑷 + 𝒉𝒊𝒏𝒇𝒍𝒖𝒙𝝆𝒊𝒏𝒇𝒍𝒖𝒙𝒈 + 𝑯 − 𝒉𝒊𝒏𝒇𝒍𝒖𝒙 𝝆𝒎𝒈 𝑬𝒒𝒖𝒂𝒕𝒊𝒐𝒏 𝟐

Interpretation of Shut-in Pressures When an influx has occurred, and the well has subsequently been shut-in, the pressures on the drill pipe and the annulus at surface can be used to determine: the formation pore pressure, the mud weight required to kill the well and the height and type of influx. 𝑯𝒆𝒊𝒈𝒉𝒕 𝒐𝒇 𝑰𝒏𝒇𝒍𝒖𝒙 𝒇𝒕 =𝑷𝒊𝒕 𝒈𝒂𝒊𝒏 𝒃𝒃𝒍𝒔 𝑨𝒏𝒏𝒖𝒍𝒂𝒓 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒃𝒃𝒍𝒔 𝒇𝒕 𝑯𝒆𝒊𝒈𝒉𝒕 𝒐𝒇 𝑰𝒏𝒇𝒍𝒖𝒙 = 𝒉𝒊𝒏𝒇𝒍𝒖𝒙

Interpretation of Shut-in Pressures The type of influx can be obtained by equating equation 1 and 2 as follows; 𝑆𝐼𝐷𝑃 + 𝐻𝜌𝑚𝑔 = 𝑆𝐼𝐶𝑃 + ℎ𝑖𝑛𝑓𝑙𝑢𝑥𝜌𝑖𝑛𝑓𝑙𝑢𝑥𝑔 + 𝐻 − ℎ𝑖𝑛𝑓𝑙𝑢𝑥 𝜌𝑚𝑔 𝑆𝐼𝐷𝑃 + 𝐻𝜌𝑚 × 0.052 = 𝑆𝐼𝐶𝑃 + ℎ𝑖𝑛𝑓𝑙𝑢𝑥𝜌𝑖𝑛𝑓𝑙𝑢𝑥 × 0.052 + 𝐻 − ℎ𝑖𝑛𝑓𝑙𝑢𝑥 𝜌𝑚 × 0.052 𝑆𝐼𝐷𝑃 = 𝑆𝐼𝐶𝑃 + 0.052ℎ𝑖𝑛𝑓𝑙𝑢𝑥𝜌𝑖𝑛𝑓𝑙𝑢𝑥 − 0.052ℎ𝑖𝑛𝑓𝑙𝑢𝑥𝜌𝑚 0.052ℎ𝑖𝑛𝑓𝑙𝑢𝑥𝜌𝑖𝑛𝑓𝑙𝑢𝑥 = 𝑆𝐼𝐷𝑃 − 𝑆𝐼𝐶𝑃 + 0.052ℎ𝑖𝑛𝑓𝑙𝑢𝑥𝜌𝑚 𝐷𝑖𝑣𝑖𝑑𝑒 𝑡ℎ𝑟𝑜𝑢𝑔ℎ 𝑏𝑦 ℎ𝑖𝑛𝑓𝑙𝑢𝑥 𝑜𝑛 𝑏𝑜𝑡ℎ 𝑠𝑖𝑑𝑒𝑠 𝑡𝑜 𝑐𝑟𝑒𝑎𝑡𝑒 𝑎 𝑓𝑙𝑢𝑖𝑑 𝑔𝑟𝑎𝑑𝑖𝑒𝑛𝑡 𝑜𝑛 𝑡ℎ𝑒 𝑙𝑒𝑓𝑡 ℎ𝑎𝑛𝑑 𝑠𝑖𝑑𝑒 𝑰𝒏𝒇𝒍𝒖𝒙 𝑭𝒍𝒖𝒊𝒅 𝒈𝒓𝒂𝒅𝒊𝒆𝒏𝒕(𝒑𝒔𝒊/𝒇𝒕) = 𝑺𝑰𝑫𝑷 − 𝑺𝑰𝑪𝑷𝒉𝒊𝒏𝒇𝒍𝒖𝒙 + 𝟎. 𝟎𝟓𝟐𝝆𝒎 𝑊ℎ𝑒𝑟𝑒 𝑆𝐼𝐷𝑃: 𝑆ℎ𝑢𝑡 − 𝑖𝑛 𝐷𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑝𝑠𝑖 ; 𝑆𝐼𝐶𝑃: 𝑆ℎ𝑢𝑡 − 𝑖𝑛 𝐶𝑎𝑠𝑖𝑛𝑔 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑝𝑠𝑖 ; ℎ𝑖𝑛𝑓𝑙𝑢𝑥 − 𝐻𝑒𝑖𝑔ℎ𝑡 𝑜𝑓 𝑖𝑛𝑓𝑙𝑢𝑥 (𝑓𝑡) 𝜌𝑖𝑛𝑓𝑙𝑢𝑥 − 𝐼𝑛𝑓𝑙𝑢𝑥 𝑑𝑒𝑛𝑠𝑖𝑡𝑦 𝑝𝑝𝑔 ; 𝜌𝑚 − 𝑜𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝑚𝑢𝑑 𝑑𝑒𝑛𝑠𝑖𝑡𝑦 𝑝𝑝𝑔

Shut-in Pressures Interpretation of Shut-in Pressures

Tertiary Control is the control of formation pressure by pumping heavy mud from the surface into the well to stop the influx of formation fluids.  After identifying the influx fluid type using the influx fluid gradient, it is necessary to calculate the mud weight needed to balance bottomhole formation pressure.  The kill mud weight is the mud weight required to balance the formation pressure. 𝑲𝒊𝒍𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕(𝒑𝒑𝒈) = 𝑰𝒏𝒊𝒕𝒊𝒂𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕(𝒑𝒑𝒈) + 𝑺𝑰𝑫𝑷(𝒑𝒔𝒊) 𝑻𝑽𝑫(𝒇𝒕) × 𝒈 ⟹ 𝑲𝒊𝒍𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 = 𝑰𝒏𝒊𝒕𝒊𝒂𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 + 𝑺𝑰𝑫𝑷(𝒑𝒔𝒊) 𝑻𝑽𝑫 𝒇𝒕 × 𝟎. 𝟎𝟓𝟐 𝑾𝒉𝒆𝒓𝒆 𝑻𝑽𝑫 − 𝑻𝒐𝒕𝒂𝒍 𝑽𝒆𝒓𝒕𝒊𝒄𝒂𝒍 𝑫𝒆𝒑𝒕𝒉

Circulating the Kill Mud  A slow pump rate is preferred while performing a killing operation, the killing flow rate is normally one third to a half of normal drilling flow rate.  The kill mud is circulated at a constant pump rate, the Slow Circulation Rate (SCR). 𝑰𝑪𝑷 = 𝑺𝑰𝑫𝑷 + 𝑺𝑪𝑹 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒘𝒉𝒆𝒓𝒆 𝑰𝑪𝑷 − 𝑰𝒏𝒊𝒕𝒊𝒂𝒍 𝑪𝒊𝒓𝒄𝒖𝒍𝒂𝒕𝒊𝒏𝒈 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆(𝑰𝒏𝒊𝒕𝒊𝒂𝒍 𝑫𝒓𝒊𝒍𝒍 𝒑𝒊𝒑𝒆 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆)

Circulating the Kill Mud Initial Circulating Pressure (Initial Drill Pipe Pressure) is the pressure at the top of the drillstring when the kill mud starts to enter the well while pumping kill mud into the well, which comes from the pressure gauge. 𝑰𝑪𝑷 = 𝑺𝑰𝑫𝑷 + 𝑺𝑪𝑹 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒘𝒉𝒆𝒓𝒆 𝑰𝑪𝑷 − 𝑰𝒏𝒊𝒕𝒊𝒂𝒍 𝑪𝒊𝒓𝒄𝒖𝒍𝒂𝒕𝒊𝒏𝒈 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆(𝑰𝒏𝒊𝒕𝒊𝒂𝒍 𝑫𝒓𝒊𝒍𝒍 𝒑𝒊𝒑𝒆 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆)

TERTIARY CONTROL Circulating the Kill Mud o Final circulating pressure (FCP) is the drill pipe pressure reading when the kill mud reaches the bit. o FCP balances the string side of the u-tube and should be maintained for the remainder of the well kill operation. 𝑭𝒊𝒏𝒂𝒍 𝑪𝒊𝒓𝒄𝒖𝒍𝒂𝒕𝒊𝒏𝒈 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝑭𝑪𝑷 = 𝑺𝑪𝑹 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 × 𝑲𝒊𝒍𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕

Maximum Allowable Annular Surface Pressure (MAASP) o When a well has to be shut in, in order to control a kick, surface shutin pressure is required to balance the bottom hole pressure. o At the time of shut-in, there are two pressures acting at the shoe: mud hydrostatic + shut-in pressure applied from surface. o These two pressures, combined, cannot exceed the fracture pressure of the formation at the shoe (Pfrac determined from the leak off test(LOT)). 𝑷𝒇𝒓𝒂𝒄 > 𝑯𝒚𝒅𝒓𝒐𝒔𝒕𝒂𝒕𝒊𝒄 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒂𝒕 𝒕𝒉𝒆 𝑺𝒉𝒐𝒆 + 𝑺𝒉𝒖𝒕 − 𝒊𝒏 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆

Maximum Allowable Annular Surface Pressure (MAASP) The MAASP is the maximum shut-in pressure that can be allowed to develop at surface before the fracture pressure of the formation just below the casing shoe is exceeded. 𝑷𝒇𝒓𝒂𝒄 = 𝑯𝒀𝑫𝒔𝒉𝒐𝒆 + 𝑴𝑨𝑨𝑺𝑷 ⟹ 𝑴𝑨𝑨𝑺𝑷 = 𝑷𝒇𝒓𝒂𝒄 − 𝑯𝒀𝑫𝒔𝒉𝒐𝒆 𝑾𝒉𝒆𝒓𝒆 𝑷𝒇𝒓𝒂𝒄 − 𝑭𝒓𝒂𝒄𝒕𝒖𝒓𝒆 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒐𝒇 𝒕𝒉𝒆 𝒇𝒐𝒓𝒎𝒂𝒕𝒊𝒐𝒏 𝒂𝒕 𝒕𝒉𝒆 𝒔𝒉𝒐𝒆 𝒇𝒓𝒐𝒎 𝑳𝑶𝑻 𝑯𝒀𝑫𝒔𝒉𝒐𝒆 − 𝑴𝒖𝒅 𝒉𝒚𝒅𝒓𝒐𝒔𝒕𝒂𝒕𝒊𝒄 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒂𝒕 𝒕𝒉𝒆 𝒔𝒉𝒐𝒆 At the time of an LOT, the MAASP is clearly equal to the Leak Off Pressure, since this is the shut-in pressure that actually causes fracture.

Maximum Allowable Annular Surface Pressure (MAASP) Example – MAASP A LOT is performed at a shoe depth of 4000ft TVD, with a mud weight of 10.5 ppg. Leak off pressure is 1500psi. What is the MAASP, if at 6000ft MD, mud weight has to be increased to 11.2ppg? Solution 𝑷𝒇𝒓𝒂𝒄 = 𝑯𝒀𝑫𝒔𝒉𝒐𝒆 + 𝑴𝑨𝑨𝑺𝑷 = 𝟒𝟎𝟎𝟎 × 𝟏𝟎. 𝟓 × 𝟎. 𝟎𝟓𝟐 + 𝟏𝟓𝟎𝟎 = 𝟑𝟔𝟖𝟒𝒑𝒔𝒊 For the 11.2ppg mud MAASP will be obtained from; 𝑴𝑨𝑨𝑺𝑷 = 𝑷𝒇𝒓𝒂𝒄 − 𝑯𝒀𝑫𝒔𝒉𝒐𝒆 = 𝟑𝟔𝟖𝟒 − 𝟒𝟎𝟎𝟎 × 𝟏𝟏. 𝟐 × 𝟎. 𝟎𝟓𝟐 = 𝟏𝟑𝟓𝟒. 𝟒𝒑𝒔𝒊

Example – Well Killing operations A kick is taken while drilling a 12 1/4” hole at 7500 feet (MD and TVD). The present mud weight is 10.2ppg. The 13 3/8” casing shoe (ID 12.72”) is set at 4000 feet. A leak off test performed with 9ppg mud gave a leak off pressure of 1500psi. The pump capacity is 0.102 bbls/stroke The drill string is composed of: Drill pipe OD 5.0”, ID 4.28” HWDP 500ft OD 5.0”, ID 3.0” DC 600ft OD 8.5”, ID 3.0” The last SCR’s taken gave 220psi at 30 spm. A pit gain of 8 bbls was taken and the shut-in pressures are SIDP 280psi and SICP 330psi. Delivered by Kalitaani Shem; BSc. Pet. Geosci. & Prodn. (MUK), M. Eng. Oil & Natural Gas Eng. –CUP - China Well Control Example – Well Killing operations 1) Calculate (bbls/ft) the pipe capacity for each section 2) Calculate (bbls/ft) the annular capacity for each section 3) Calculate the fracture gradient at the shoe. 4) At the time of the kick, calculate a) the present hydrostatic pressure b) the present MAASP 5) Calculate the density of mud required to kill the well 6) Calculate the initial and final circulating pressures 7) Calculate a) strokes from surface to bit b) strokes from bit to casing shoe c) strokes from casing shoe to surface 8) Calculate the height of the influx 9) Calculate the gradient of the influx 10) What type of influx produced the kick? Delivered by Kalitaani Shem; BSc. Pet. Geosci. & Prodn. (MUK), M. Eng. Oil & Natural Gas Eng. –CUP - China Well Control Example – Well Killing operations Solution Casing Shoe 3500ft 4000ft 6400ft Drillpipe 500ft HWDP 600ft DC

Example – Well Killing operations Solution Drill pipe HWDP Drill Collars 𝐕𝐨𝐥𝐮𝐦𝐞 = 𝛑𝐫 𝟐𝐡 𝐟𝐭𝟑 = 𝛑 × (𝟎. 𝟑𝟔𝟐 )𝟐 × 𝟔𝟒𝟎𝟎 𝐕𝐨𝐥𝐮𝐦𝐞 = 𝟔𝟓𝟏. 𝟒𝟒𝐟𝐭𝟑 Volume in bbl/ft3 can be obtained by dividing by h and changing ft3 to barrels using the conversion factor 1bbl = ft3*0.17811 𝐕 = 𝟔𝟓𝟏. 𝟒𝟒 × 𝟎. 𝟏𝟕𝟖𝟏𝟏 𝟔𝟒𝟎𝟎 𝐕 = 𝟎. 𝟎𝟏𝟖 𝐛𝐛𝐥𝐬 𝐟𝐭 𝐕𝐨𝐥𝐮𝐦𝐞 = 𝛑𝐫 𝟐𝐡 𝐟𝐭𝟑 = 𝛑 × ( 𝟎. 𝟐𝟓 𝟐 ) 𝟐 × 𝟓𝟎𝟎 𝐕𝐨𝐥𝐮𝐦𝐞 = 𝟐𝟓. 𝟓𝟒𝟑𝟔𝐟𝐭𝟑 𝐕 = 𝟐𝟓. 𝟓𝟒𝟑𝟔 × 𝟎. 𝟏𝟕𝟖𝟏𝟏 𝟓𝟎𝟎 𝐕 = 𝟎. 𝟎𝟎𝟖𝟕𝟒 𝐛𝐛𝐥𝐬 𝐟𝐭 𝐕𝐨𝐥𝐮𝐦𝐞 = 𝛑𝐫 𝟐𝐡 𝐟𝐭𝟑 = 𝛑 × ( 𝟎. 𝟐𝟓 𝟐 ) 𝟐 × 𝟔𝟎𝟎 𝐕𝐨𝐥𝐮𝐦𝐞 = 𝟐𝟗. 𝟒𝟓𝟐𝟒𝐟𝐭𝟑 𝐕 = 𝟐𝟗. 𝟒𝟓𝟐𝟒 × 𝟎. 𝟏𝟕𝟖𝟏𝟏 𝟔𝟎𝟎 𝐕 = 𝟎. 𝟎𝟎𝟖𝟕𝟒 𝐛𝐛𝐥𝐬 𝐟𝐭

Example – Well Killing operations Solution Drill pipe / Casing 𝑉 = 𝜋 𝑟𝑐𝑎𝑠𝑖𝑛𝑔 2 ℎ 𝑓𝑡3 𝑉 = 𝜋( 1.06 2 ) 2 × 4000 𝑉 = 3529.89𝑓𝑡3 𝑉 = 3529.89 × 0.17811 4000 𝑽 = 𝟎. 𝟏𝟓𝟕𝟏 𝒃𝒃𝒍𝒔 𝒇𝒕 𝑉 = 𝜋 𝑟𝑑𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒 2 ℎ 𝑓𝑡3 𝑉 = 𝜋( 0.42 2 ) 2 × 4000 𝑉 = 554.176𝑓𝑡3 𝑉 = 554.176 × 0.17811 4000 𝑽 = 𝟎. 𝟎𝟐𝟒𝟔 𝒃𝒃𝒍𝒔 𝒇𝒕 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 = 0.1571 − 0.0246 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 = 𝟎. 𝟏𝟑𝟐𝟓 𝒃𝒃𝒍𝒔 𝒇𝒕 Drill pipe /Hole 𝑉 = 𝜋 𝑟𝑑𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒 2 ℎ 𝑓𝑡3 𝑉 = 𝜋( 0.42 2 ) 2 × 2400 𝑉 = 332.506𝑓𝑡3 𝑉 = 332.506 × 0.17811 2400 𝑽 = 𝟎. 𝟎𝟐𝟒𝟔𝟖 𝒃𝒃𝒍𝒔 𝒇𝒕 𝑉 = 𝜋 𝑟ℎ𝑜𝑙𝑒 2ℎ 𝑓𝑡3 𝑉 = 𝜋( 1.02 2 ) 2 × 2400 𝑉 = 1961.107𝑓𝑡3 𝑉 = 1961.107 × 0.17811 2400 𝑽 = 𝟎. 𝟏𝟒𝟓𝟓 𝒃𝒃𝒍𝒔 𝒇𝒕 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 = 0.1455 − 0.02468 = 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 = 𝟎. 𝟏𝟐𝟎𝟖𝟐 𝒃𝒃𝒍𝒔 𝒇𝒕

Example – Well Killing operations Solution HWDP/hole 𝑉 = 𝜋 𝑟𝐻𝑊𝐷𝑃 2ℎ 𝑓𝑡3 𝑉 = 𝜋( 0.42 2 ) 2 × 500 𝑉 = 69.272𝑓𝑡3 𝑉 = 69.272 × 0.17811 500 𝑽 = 𝟎. 𝟎𝟐𝟒𝟔𝟖 𝒃𝒃𝒍𝒔 𝒇𝒕 𝑉 = 𝜋 𝑟ℎ𝑜𝑙𝑒 2ℎ 𝑓𝑡3 𝑉 = 𝜋( 1.02 2 ) 2 × 500 𝑉 = 408.56𝑓𝑡3 𝑉 = 408.56 × 0.17811 500 𝑽 = 𝟎. 𝟏𝟒𝟓𝟓 𝒃𝒃𝒍𝒔 𝒇𝒕 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 = 0.1455 − 0.02468 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 = 𝟎. 𝟏𝟐𝟎𝟖 𝒃𝒃𝒍𝒔 𝒇𝒕 DC/hole 𝑉 = 𝜋 𝑟ℎ𝑜𝑙𝑒 2ℎ 𝑓𝑡3 𝑉 = 𝜋( 1.02 2 ) 2 × 600 𝑉 = 490.27𝑓𝑡3 𝑉 = 490.27 × 0.17811 600 𝑽 = 𝟎. 𝟏𝟒𝟓𝟓 𝒃𝒃𝒍𝒔 𝒇𝒕 𝑉 = 𝜋 𝑟𝐷𝐶 2ℎ 𝑓𝑡3 𝑉 = 𝜋( 0.71 2 ) 2 × 600 𝑉 = 237.552𝑓𝑡3 𝑉 = 237.552 × 0.17811 600 𝑽 = 𝟎. 𝟎𝟕𝟎𝟓 𝒃𝒃𝒍𝒔 𝒇𝒕 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 = 0.1455 − 0.0705 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 = 𝟎. 𝟎𝟕𝟒𝟗𝟖 𝒃𝒃𝒍𝒔 𝒇𝒕

Example – Well Killing operations Solution Fracture gradient at the shoe 𝑴𝒖𝒅 𝒉𝒚𝒅𝒓𝒐𝒔𝒕𝒂𝒕𝒊𝒄 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒂𝒕 𝒕𝒉𝒆 𝒔𝒉𝒐𝒆 = 𝟎. 𝟎𝟓𝟐 × 𝟗 × 𝟒𝟎𝟎𝟎 = 𝟏𝟖𝟕𝟐𝒑𝒔𝒊 𝑭𝒓𝒂𝒄𝒕𝒖𝒓𝒆 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 = 𝒍𝒆𝒂𝒌 𝒐𝒇𝒇 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 + 𝒎𝒖𝒅 𝒉𝒚𝒅. 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒂𝒕 𝒕𝒉𝒆 𝒔𝒉𝒐𝒆 𝑭𝒓𝒂𝒄𝒕𝒖𝒓𝒆 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 = 𝟏𝟖𝟕𝟐 + 𝟏𝟓𝟎𝟎 = 𝟑𝟑𝟕𝟐𝒑𝒔𝒊 𝑭𝒓𝒂𝒄𝒕𝒖𝒓𝒆 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒈𝒓𝒂𝒅𝒊𝒆𝒏𝒕 = 𝟑𝟑𝟕𝟐 𝟒𝟎𝟎𝟎 = 𝟎. 𝟖𝟒𝟑 𝒑𝒔𝒊 𝒇𝒕

Example – Well Killing operations Solution At the time of the kick, calculate a) the present hydrostatic pressure b) the present MAASP 𝑴𝒖𝒅 𝒉𝒚𝒅𝒓𝒐𝒔𝒕𝒂𝒕𝒊𝒄 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 = 𝟎. 𝟎𝟓𝟐 × 𝟏𝟎. 𝟐 × 𝟕𝟓𝟎𝟎 = 𝟑𝟗𝟕𝟖𝒑𝒔𝒊 𝑴𝑨𝑨𝑺𝑷 = 𝑭𝒓𝒂𝒄𝒕𝒖𝒓𝒆 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 − 𝑴𝒖𝒅 𝒉𝒚𝒅𝒓𝒐𝒔𝒕𝒂𝒕𝒊𝒄 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒂𝒕 𝒕𝒉𝒆 𝒔𝒉𝒐𝒆 𝑴𝑨𝑨𝑺𝑷 = 𝟑𝟑𝟕𝟐 − 𝟏𝟎. 𝟐 × 𝟎. 𝟎𝟓𝟐 × 𝟒𝟎𝟎𝟎 = 𝟏𝟐𝟓𝟎. 𝟒𝒑𝒔𝒊

Example – Well Killing operations Solution Density of the mud required to kill a well 𝑲𝒊𝒍𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 = 𝑰𝒏𝒊𝒕𝒊𝒂𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 + 𝑺𝑰𝑫𝑷 𝒑𝒔𝒊 𝑻𝑽𝑫 𝒇𝒕 × 𝟎. 𝟎𝟓𝟐 𝑲𝒊𝒍𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 = 𝟏𝟎. 𝟐 + 𝟐𝟖𝟎 𝟕𝟓𝟎𝟎 × 𝟎. 𝟎𝟓𝟐 = 𝟏𝟎. 𝟗𝟐𝒑𝒑𝒈

Example – Well Killing operations Solution Initial and final circulating pressures 𝑰𝑪𝑷 = 𝑺𝑰𝑫𝑷 + 𝑺𝑪𝑹 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 = 𝟐𝟖𝟎 + 𝟐𝟐𝟎 = 𝟓𝟎𝟎𝒑𝒔𝒊 𝑭𝒊𝒏𝒂𝒍 𝑪𝒊𝒓𝒄𝒖𝒍𝒂𝒕𝒊𝒏𝒈 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝑭𝑪𝑷 = 𝑺𝑪𝑹 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 × 𝑲𝒊𝒍𝒍 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕 𝑭𝒊𝒏𝒂𝒍 𝑪𝒊𝒓𝒄𝒖𝒍𝒂𝒕𝒊𝒏𝒈 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝑭𝑪𝑷 = 𝟐𝟐𝟎 × 𝟏𝟎. 𝟗𝟐 𝟏𝟎. 𝟐 = 𝟐𝟑𝟓. 𝟓𝒑𝒔𝒊

Example – Well Killing operations Solution a) strokes from surface to bit 𝑺𝒕𝒓𝒐𝒌𝒆𝒔 = 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒃𝒃𝒍𝒔 𝒑𝒖𝒎𝒑 𝒄𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒃𝒃𝒍 𝒔𝒕𝒓𝒐𝒌𝒆 = 𝟔𝟓𝟏. 𝟒𝟒 × 𝟎. 𝟏𝟕𝟖𝟏𝟏 + 𝟐𝟓. 𝟓𝟒𝟑𝟔 × 𝟎. 𝟏𝟕𝟖𝟏𝟏 + 𝟐𝟗. 𝟒𝟓𝟐𝟒 × 𝟎. 𝟏𝟕𝟖𝟏𝟏 𝟎. 𝟏𝟎𝟐 𝑺𝒕𝒓𝒐𝒌𝒆𝒔 𝒇𝒓𝒐𝒎 𝒔𝒖𝒓𝒇𝒂𝒄𝒆 𝒕𝒐 𝒃𝒊𝒕 = 𝟏𝟐𝟑𝟑𝒔𝒕𝒓𝒐𝒌𝒆𝒔

Example – Well Killing operations Solution b) strokes from bit to casing shoe 𝑺𝒕𝒓𝒐𝒌𝒆𝒔 = 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒃𝒃𝒍𝒔 𝒑𝒖𝒎𝒑 𝒄𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒃𝒃𝒍 𝒔𝒕𝒓𝒐𝒌𝒆 = 𝟎. 𝟎𝟕𝟒𝟗𝟖 × 𝟔𝟎𝟎 + 𝟎. 𝟏𝟐𝟎𝟖 × 𝟓𝟎𝟎 + 𝟎. 𝟏𝟐𝟎𝟖𝟐 × 𝟐𝟒𝟎𝟎 𝟎. 𝟏𝟎𝟐 𝑺𝒕𝒓𝒐𝒌𝒆𝒔 𝒇𝒓𝒐𝒎 𝒃𝒊𝒕 𝒕𝒐 𝒕𝒉𝒆 𝒄𝒂𝒔𝒊𝒏𝒈 𝒔𝒉𝒐𝒆 = 𝟑𝟖𝟕𝟔𝒔𝒕𝒓𝒐𝒌𝒆𝒔

Example – Well Killing operations Solution c) strokes from casing shoe to surface 𝑺𝒕𝒓𝒐𝒌𝒆𝒔 = 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒃𝒃𝒍𝒔 𝒑𝒖𝒎𝒑 𝒄𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒃𝒃𝒍 𝒔𝒕𝒓𝒐𝒌𝒆 = 𝟎. 𝟏𝟑𝟐𝟓 × 𝟒𝟎𝟎𝟎 𝟎. 𝟏𝟎𝟐 𝑺𝒕𝒓𝒐𝒌𝒆𝒔 𝒇𝒓𝒐𝒎 𝒄𝒂𝒔𝒊𝒏𝒈 𝒔𝒉𝒐𝒆 𝒕𝒐 𝒔𝒖𝒓𝒇𝒂𝒄𝒆 = 𝟓𝟏𝟗𝟔𝒔𝒕𝒓𝒐𝒌𝒆𝒔

Example – Well Killing operations Solution Height of influx 𝑯𝒆𝒊𝒈𝒉𝒕 𝒐𝒇 𝑰𝒏𝒇𝒍𝒖𝒙 𝒇𝒕 = 𝑷𝒊𝒕 𝒈𝒂𝒊𝒏 𝑨𝒏𝒏𝒖𝒍𝒂𝒓 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 = 𝟖𝒃𝒃𝒍𝒔 𝟎. 𝟎𝟕𝟒𝟗𝟖 = 𝟏𝟎𝟔. 𝟔𝟗 𝒇𝒆𝒆𝒕

Example – Well Killing operations Solution Influx gradient 𝑰𝒏𝒇𝒍𝒖𝒙 𝑭𝒍𝒖𝒊𝒅 𝒈𝒓𝒂𝒅𝒊𝒆𝒏𝒕 𝒑𝒔𝒊 𝒇𝒕 = 𝑺𝑰𝑫𝑷 − 𝑺𝑰𝑪𝑷 𝒉𝒊𝒏𝒇𝒍𝒖𝒙 + 𝟎. 𝟎𝟓𝟐𝝆𝒎 𝑰𝒏𝒇𝒍𝒖𝒙 𝑭𝒍𝒖𝒊𝒅 𝒈𝒓𝒂𝒅𝒊𝒆𝒏𝒕 𝒑𝒔𝒊 𝒇𝒕 = 𝟐𝟖𝟎 − 𝟑𝟑𝟎 𝟏𝟎𝟔. 𝟔𝟗 + 𝟎. 𝟎𝟓𝟐 × 𝟏𝟎. 𝟐 = 𝟎. 𝟎𝟔𝟏𝟕𝟓 𝒑𝒔𝒊 𝒇𝒕

Example – Well Killing operations Solution Influx type Influx Fluid Gradient (psi/ft) Fluid Type Influx Fluid Gradient (KPa/m) 0.05-0.15 Gas 1.131-3.393 0.15-0.40 Condensate-Oil 3.393-9.048 0.433 Fresh water 9.795 0.433-0.48 Salt water 9.795-10.858 Influx type is gas

Exercise – Well Killing operations 1. A kick was detected while drilling a high-pressure zone. The depth of the formation was recorded 10,000 ft. with a mud density of 9.0 ppg. The crew shut-in the well and they recorded the pressure for drill pipe and drill collar as 350 psi and 430 psi respectively. The observed total pit gain was 6.0 bbl. The annular capacity against 950 ft. drill collar is 0.0280 bbl/ft. and the overkill safety margin is 0.50 ppg. Compute the: a) formation pressure b) influx density c) type of fluid d) required kill mud weight e) kill mud gradient

Exercise – Well Killing operations 2. A well was being drilled at a high-pressure zone of 12,000 ft. vertical depth where 9.5 ppg mud was being circulated at a rate of 8.0 bbl/min. A pit gain of 95 bbl was noticed over a 3 minutes period before the pump was stopped and the BOPs were closed. After the pressures stabilized, an initial drill pipe pressure of 500 psi and an initial casing pressure of 700 psi were recorded by the attendees at the rig side. The annular capacity against 950 ft. drill collar was 0.03 bbl/ft. and the annular capacity against 850 ft. of drill pipe was 0.0775 bbl/ft. Compute the formation: a) Formation pressure b) Influx density

Exercise – Well Killing operations 3. While drilling ahead at a target of 8,500 ft., the hole size was 7 in. The drilling crew noticed that there was a pit gain of 10 bbls. The well is shut-in and the drill pipe and the annulus pressures were recorded as 650 psi, and 800 psi respectively. The bottomhole assembly consists of 650 ft. of 𝟒 𝟑 𝟒 " OD collars and 𝟑 " drill pipe. The mud weight is 10.2 ppg. a) Assume a mud pressure gradient b) Identify the influx c) Calculate the new mud weight, including an overbalance of 250 psi.

Exercise – Well Killing operations 4. Determine the kill mud density and kill mud gradient for a shut-in drill pipe pressure of 600 psi at a depth of 12,000 ft. If the original mud weight is 14.5 ppg and the slow circulating pump pressure is 850 psi, find out also the initial and final circulating pressure of the system.

Kick Tolerance Mud weight must, clearly, be sufficient to exert a pressure that will balance the formation pressure and prevent a kick, but it cannot be so high that the resulting pressure would cause a formation to fracture. KICK TOLERANCE is the maximum balance gradient (i.e. mud weight) that can be handled by a well, at the current TVD, without fracturing the shoe should the well have to be shut in. 𝑲𝒊𝒄𝒌 𝑻𝒐𝒍𝒆𝒓𝒂𝒏𝒄𝒆 = 𝑻𝑽𝑫𝑺𝑯𝑶𝑬 × 𝑬𝑴𝑾 − 𝑴𝑾 𝑻𝑽𝑫𝑯𝑶𝑳𝑬 𝑾𝒉𝒆𝒓𝒆 𝑬𝑴𝑾 − 𝑬𝒒𝒖𝒊𝒗𝒂𝒍𝒆𝒏𝒕 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕; 𝑴𝑾 − 𝑴𝒖𝒅 𝑾𝒆𝒊𝒈𝒉𝒕; 𝑻𝑽𝑫𝑯𝑶𝑳𝑬 − 𝑯𝒐𝒍𝒆 𝑻𝒐𝒕𝒂𝒍 𝑽𝒆𝒓𝒕𝒊𝒄𝒂𝒍 𝑫𝒆𝒑𝒕𝒉

WELL CONTROL METHODS There are 4 methods of well control namely;  Wait and Weight  Driller’s method  Concurrent Method  Volumetric Method.

WELL CONTROL METHODS Wait and Weight Method  The well is shut in while the mud is weighted up to the required kill weight, calculations and kill sheets are prepared. Only one circulation is required to kill the well  Advantages: • Lower pressures are imposed on the well, since the pressure increase from gas expansion is compensated, to some extent, by displacing the well to heavier kill mud at the same time • Generally faster since the kick is circulated out and the well killed in a minimum of one circulation • Safer • Less wear on surface gas equipment and choke (because of minimum choke circulating time)  Disadvantages • Circulation must wait until kill mud is ready • More calculations required • If large increases in mud weight required, this is difficult to do uniformly in one stage.

WELL CONTROL METHODS Wait and Weight Method Procedures  Shut well in and weight required volume of mud to kill mud-weight  Open choke and bring pump up to the designated kill pump rate  Maintain constant kill rate as kill mud is pumped down the string  Follow the “SIDP” step down procedure by adjusting casing choke (A). • If the actual stabilized ICP is not the same as the calculated ICP, the step down sequence should be adjusted accordingly • A reduction in SICP will be seen as the influx passes from drill collars to drillpipe (B), since the larger annular capacity reduces the influx height, increasing the overall hydrostatic in the annulus  When kill mud is at the bit, the drillpipe pressure should equal FCP (C) • Adjust the choke to maintain this pressure for the complete operation • A reduction in SICP will be seen as kill mud enters annulus, increasing the overall hydrostatic in the annulus (D)

WELL CONTROL METHODS Wait and Weight Method Procedures  Bring influx to surface…as gas expands, SICP and pit levels increase (E)  Gas needs to bled off to maintain drillpipe pressure and keep SICP within limits so as not to fracture the shoe (F) Kill mud at surface Kill mud at bit Influx arrives at surface Influx removed SICP Drillpipe pressure A B C D E F

Wait and Weight Method Post Kill Procedures  When kill mud reaches surface, pumping can stop and the well shut in  The well should be killed, but if some SICP still exists, continue circulating until remaining influx is removed  For offshore rigs, the riser now has to be displaced to kill mud (remember, kill mud is circulated to/from the well through the choke lines)  Open diverter and flow check well  Throughout, constant BHP is maintained with: • Constant kill mudweight • Constant slow circulation pump rate • Constant drillpipe pressure once the string is displaced to FCP

WELL CONTROL METHODS Driller’s Method  Under controlled conditions, one circulation brings the influx out of the hole using the existing mud.  At the same time, calculations are made, kill sheets completed and the mud weighted up to the required kill weight.  A second circulation displaces the well to kill mud, killing the well.  Typically used in situations such as circulating out large gas shows, trip gases, or kicks that have been swabbed into the hole, since a mudweight increase will not be required  Advantages • Immediate circulation • Simpler technique with fewer calculations  Disadvantages • More time required for the two circulations • Higher annular pressures • More wear on choke and gas equipment

WELL CONTROL METHODS Driller’s Method Procedures - circulation 1  Open choke and bring pump up to desired slow circulation rate  Circulate influx to surface at constant pump rate and maintain constant drillpipe pressure (A) by adjusting the choke. This should provide sufficient BHP to prevent further influx  Gas must be allowed to expand and mud displaced at surface.  Correspondingly, SICP increases (B)…this will help to prevent further influx, but it cannot exceed fracture pressures  Once the influx is out of the well, shut in well and record pressures (C) • If SIDP and SICP are zero, the well is dead and the mud density is sufficient to balance the well • If SIDP and SICP are equal (>0), mudweight must be increased to balance the formation pressure • If SICP > SIDP, there is still influx in the annulus and a second kick, or further influx has occurred during the initial circulation • Repeat process until influx has been completely removed

WELL CONTROL METHODS Driller’s Method Procedures - circulation 2  An assumption is made, that prior to step 2, all influx fluids have been removed from the annulus (typically, however, if influx remains, the kill will proceed according to the wait and weight method)  Open choke and bring pump up to the slow circulation rate  Pump kill mud at constant rate, maintain constant SICP by adjusting the choke (D). This will allow the drillpipe pressure to decline as the kill mud is pumped down to the bit and hydrostatic increases  When the kill mud reaches the bit, the well is dead on the drillpipe side. Record the drillpipe pressure, FCP (E)  Continue circulation, displacing the annulus to kill mud, while maintaining constant drillpipe pressure (F). SICP will decrease as kill mud displaces the annulus.  Once kill mud reaches surface, stop pumping, shut in well and confirm that it is dead.

WELL CONTROL METHODS Driller’s Method SICP Drillpipe pressure A B C D E F STEP 1 STEP 2 Influx at surface Influx removed Kill mud at bit Well Dead

WELL CONTROL METHODS Concurrent Method  Mud is gradually weighted up as circulation proceeds, until the final kill mud reaches surface and the well is dead.  Disadvantages • Higher pressures imposed on the annulus • Barite mixing and mud weight may not be consistent throughout  Procedure • With the well shut in, calculate ICP, kill mudweight and FCP • Rather than stroke increments from surface to bit, determine the pressure reduction required in terms of incremental mudweight until the final kill mud is being circulated. Increasing the mud weight and reducing drillpipe pressure will take place over several circulations • Bring the pump up to the slow circulation rate, adjusting drillpipe pressure to the ICP by adjusting the choke • As the mud density reaches each incremental increase, the drillpipe pressure is reduced, through the choke, following the step down chart • When kill mud reaches surface, the well is dead

WELL CONTROL METHODS Concurrent Method  For each incremental increase in mudweight, drillpipe pressure is reduced. When the final kill mud is at the bit, the drillpipe pressure should be at the FCP  eg ICP = 1100psi; FCP = 700psi; MW = 10.0ppg; KMW = 12.0ppg ICP FCP MW pressure 10.0 10.2 10.4 10.6 10.8 11.0 11.2 11.4 11.6 11.8 12.0 1100 1060 1020 980 940 900 860 820 780 740 700 700 900 1100 800 1000

WELL CONTROL METHODS Volumetric Method  Used when normal kill circulation is not possible from the bottom of the hole • if drillstring is out of the hole • if drillstring is washed out or twisted off or if bit nozzles are plugged  The first part of the operation requires bringing the influx to surface. This is made possible by bleeding off mud from the annulus, allowing gas to rise. As gas expands, SICP increases. Excessive pressure is avoided by bleeding off controlled amounts of drill fluid without reducing BHP to a point that would allow further influx  Once the gas is at surface, the second part of the operation requires displacing the gas from the annulus by pumping in controlled amounts of kill mud through the kill line.  The well is gradually killed, therefore, from surface down, as kill mud displaces the gas

WELL CONTROL METHODS Volumetric Method  Information required:  Determine the degree of underbalance from the SICP gauge - the SICP pressure reflects the additional pressure required to balance the formation pressure  The mud column height (and equivalent volume) that, when bled off from the annulus, reduces the hydrostatic pressure by 100psi  height (ft) = 100psi / (MWppg * 0.052)  height (m) = 700KPa / (MWkg/𝑚3*0.00981)  volume (bbls) = height (ft) * casing capacity (bbls/ft)  volume (𝑚3) = height (m) * casing capacity (𝑚3/m)  Likewise, the volume of kill mud equivalent to 100psi needs to be determined.

WELL CONTROL METHODS Volumetric Method  Procedure - Step 1  Volumetrically bleed off mud from the annulus, while maintaining BHP, allowing influx to rise and gas to come to surface  Allow SICP to increase 200psi above the underbalance…this provides a BHP which is 200psi over formation pressure, preventing further influx  Slowly bleed off the mud volume, required to reduce the hydrostatic pressure by 100psi, from the choke, but maintaining constant SICP. SICP now reflects the underbalance + 200psi, while the BHP provides 100psi margin over the formation pressure  Close choke and allow pressure to increase by a further 100psi. SICP now reflects underbalance + 300psi, while BHP provides 200psi margin over the formation pressure  Again, maintaining constant SICP, bleed off the mud volume required to reduce hydrostatic by 100psi. SICP now reflects underbalance + 300psi, while BHP provides 100psi margin over the formation pressure  Repeat until gas is at surface

WELL CONTROL METHODS Volumetric Method  Procedure - Step 2  With gas at surface, it is now necessary to pump mud into the well through the kill line, replacing the gas and maintaining BHP to balance the formation pressure. As this is done, the gas will compress, increasing the SICP.  Record SICP  Slowly pump the mud volume, necessary to increase the hydrostatic by 100psi, into the well  Wait for the gas to separate from the mud (perhaps 15 minutes)  Slowly bleed gas from the choke, lowering the SICP to the initial value. Continue bleeding until a further 100psi drop is recorded, in order to compensate for the 100psi increase in hydrostatic pressure due to the mud pumped into the well  Repeat this procedure until all gas is removed from the annulus  Flow check; if the well is static, run pipe to the bottom. END