Well Control Principles ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Well Control Principles Primary Well Control Secondary Well Control Tertiary Well Control Hydrostatic Pressure Formation Pressure Porosity And Permeability Kill Mud Density Indications of Increasing Formation Pressure

Well Control Principles The function of Well Control can be subdivided into 3 main categories: Primary Well Control: is the use of the fluid to prevent the influx of formation fluid into the well bore. Secondary Well Control: is the use of the BOP to control the well if Primary WC can not be maintained. Tertiary Well Control: squeeze back, cement ...

when Hydrostatic Pressure = Formation Pressure The Well is Balanced: when Hydrostatic Pressure = Formation Pressure ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

The Well is Under Balanced: when Hydrostatic Pressure < Formation Pressure

The Well is Over Balanced: when Hydrostatic Pressure > Formation Pressure

Hydrostatic Pressure Because the pressure is measured in psi and depth is measured in feet, it is convenient to convert Mud Weight from ppg to a pressure gradient in psi/ft. The conversion factor is 0.052 Fluid Density (ppg) x 0.052 = Pressure gradient (psi/ft) Hydrostatic Pressure is the pressure exerted by a column of fluid at rest, and is calculated by multiplying the gradient of the fluid by the True Vertical Depth at which the pressure is being measured: Fluid gradient (psi/ft) x TVD = Hyd. Pressure(psi)

T V D ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ You have to consider the vertical height or depth of the fluid column, the shape of the hole doesn’t matter.

Normal Formation Pressure Normal formation pressure is equal to the hydrostatic pressure of the water occupying the pore spaces from the surface to the subsurface formation. Native fluid is mainly dependent on its salinity and is often considered to be: 0.465 psi/ft ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Abnormal Formation Pressure Abnormal formation pressures are any formation pressures that are greater than the hydrostatic pressure of the water occupying the pore spaces. Commonly caused by the under-compaction of shale’s, clay-stone or faulting... ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Subnormal Pressure: is defined as any formation pressure that is less than “normal” pressure. It can be due to reservoir depletion,fault … Transition Zone: is the formation in which the pressure gradient begins to change from a normal gradient to a subnormal gradient or, more usually, to an abnormal gradient.

UNDERCOMPACTED SHALES / SAND. UNCONSOLIDATED SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES SAND WITH COMMUNICATION TO SURFACE SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED ENCLOSED SAND LENS WITH FORMATION FLUID

GAS CAP Ph Pabnormal = Pf-Pg Pf Pg NORMAL FORMATION PRESSURE ABOVE CAP ROCK =0.465 PSI/FT Ph Pabnormal = Pf-Pg Pf Pg GAS PRESSURE GRADIENT = 0.1 PSI/FT COMMUNICATION BETWEEN FLUID AND GAS

SURCHARGED FORMATIONS

NATURALLY SURCHARGED FORMATIONS FAULT ZONE Pf Pf

ARTESIAN WELL NORMAL FORMATION PRESSURE AT THE WELL UNTILL BELOW THE CAP ROCK LAKE HYDROSTATIC PRESSURE FROM FORMATION WATER COLUMN POROUS SANDSTONE BELOW CAP ROCK

SURFACE EROSION ENCLOSED FORMATION LEVEL CHANGE Pf H2 Pf Pf

Porosity & Permeability The essential properties of reservoir rocks are: - Their porosity and permeability. The porosity provides the storage space for fluids and gases and is the ratio of the pore spaces in the rock to the bulk volume of the rock. This is expressed as a percentage. Reservoir rocks commonly have porosity’s ranging from 5% to 30%. Formation permeability is a measure of how easy the fluid will flow through the rock. Permeability is expressed in Darcys, from a few milliDarcys to several Darcys. These properties will determine how much and how quick a kick will enter into the well. Kicks will enter a wellbore faster from rocks having high permeability. ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Pores are connected for the Permeability ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Tiny openings in rock are pores Porosity Pores are connected for the Permeability

Formation Pressure SIDPP + Hydrostatic pressure = Formation Pressure When the well is shut in, Formation Pressure can be found with the following formula: SIDPP + Hydrostatic pressure = Formation Pressure SICP + Influx Hyd + Mud Hyd = Formation Pressure SICP + Mud Hydrostatic Influx Hydrostatic = SIDPP + Mud Hydrostatic = Formation Pressure

KICK INDICATORS

- Flow from Well (pumps off) POSITIVE KICK SIGNS Positive Indications of a kick: - Flow from Well (pumps off) - Increase in Flow from Well (pumps on) - Pit Volume Gain

KICKS WHILE TRIPPING Incorrect Fill or Return Volumes - Swabbing - Surging If any deviation, the FIRST action will be to install a fully open safety valve and make a Flow-Check. Remember: It is possible that the well will not flow even if an influx has been swabbed in.

That the well MIGHT be going under-balanced KICKS WHILE DRILLING Early Warning Signs That the well MIGHT be going under-balanced

Indications of Increasing Formation Pressure Increase in Drilling Rate Change in D - Exponent Change in Cutting size and shape Increase in Torque and Drag Chloride Trends Decrease in Shale Density Temperature Measurements Gas Cut Mud Connection Gas ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Increase in Drilling Rate: While drilling normally pressured shale and assuming a fairly constant bit weight, RPM, and hydraulic program, a normal decrease in penetration rate can be expected. When abnormal pressure is encountered, differential pressure and shale density are decreased causing a gradual increase in penetration rate. ROP Depth

Increase in Torque and Drag Increase in torque and drag often occurs when drilling under balanced through some shale intervals. There is a build up of cuttings in the annulus and this may be a sign that pore pressure is increasing. Torque Depth

Change in “d” Exponent: “d” is an indication of drill ability and ROP, RPM, WOB, bit size are used to calculate its value. Trends of “d” normally increase with depth, but in transition zones, it may decrease with lower than expected value. “d” Depth

Change in cutting size and shape Normally pressured shale: cuttings are small with rounded edges, generally flat. ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Abnormally pressured shale: cutting are long and splintery with angular edges. As differential between the pore pressure and bottom pressure is reduced, the cuttings have a tendency to “explode” of bottom.

Chloride Trends: The chloride content of the mud filtrate can be monitored both going into and coming out of the hole. A comparison of chloride trends can provide a warning or confirmation signal of increasing pore pressure. Chloride Depth

Decrease in Shale Density: Shale density normally increases with depth but decreases as abnormal pressure zones are drilled. When first deposited, shale has a high porosity. During normal compaction, a gradual reduction in porosity occurs with an increase of the overlaying sediments. Shale Density Depth

Temperature Measurements: The temperature gradient in abnormally pressured formations is generally higher than normal. Temp. Depth

Gas Cut Mud The presence of gas cut mud does not indicate that the well is kicking ( gas may have been entrained in the cutting ). However, the presence of gas cut mud must be treated as an early warning sign of a potential kick. - Gas cut mud only slightly reduces mud column pressure, when it is close to surface. - Drilled cuttings from which the gas comes may compensate for the decrease.

Connection Gas Connection gas are detected at the surface as a distinct increase above the background gas, as bottom up is circulated after a connection. Connection gases may indicate a condition of near balance. If connection gas is present, limiting its volume by controlling the drilling rate should be considered.

SYSTEM PRESSURE LOSSES

Objectives Identify the different pressures losses in the system Identify which one influence bottom hole pressure Convert this pressure to an equivalent mud weight

Mud System Pressure Losses Pumping through a pipe with a mud pump at 80 spm, with gauges mounted on the discharge of the pump and at the end of the pipe. The gauge on the pump reads 100 psi. The gauge on the end of the pipe reads 0 psi. It can be assumed from this information that the 100 psi drop in pressure through the pipe is the result of friction losses in the pipe as the fluid is pumped through it. 100 psi 0 psi 80 SPM

Mud System Pressure Losses 500 psi 100 psi 400 psi 0 psi 80 SPM

Mud System Pressure Losses 1000 psi 900 psi 100 psi 80 SPM 400 psi 500 psi 500 psi 0 psi

Mud System Pressure Losses 2300 psi 100 psi 2200 psi 1800 psi 400 psi 1300 psi 500 psi 80 SPM 0 psi

Mud System Pressure Losses 2600 psi 2500 psi 0 psi 100 psi 80 SPM Annular Pressure Losses 400 psi 300 psi 2100 psi 500 psi 1600 psi 1300 psi 300 psi

Mud System Pressure Losses APL EXAMPLE 0 psi 0 psi A well has been drilled to 10,000 ft. The mud weight is 10 ppg. To find our Hydrostatic pressure we use the following formula; Mud Wt x 0.052 x TVD 10 x 0.052 x 10,000 = 5,200psi. The gauge on the drawing shows bottom hole hydrostatic pressure. 0 psi 0 SPM 10,000 ft TVD MUD WT = 10 ppg 0 psi 0 psi 5200 psi

Mud System Pressure Losses APL EXAMPLE 2600 psi 100 psi 2500 psi 2100 psi 400 psi 1600 psi 500 psi 1300 psi 0 psi 5500 psi 300 psi If we now start to circulate at 80 spm through our system with the same pressure losses as before. As you can see from this example the bottom hole pressure has increased by 300 psi. This increase is due to the Annular Pressure Losses (APL) acting down on the bottom of the well and is usually called “Bottom Hole Circulating Pressure” (BHCP) 80 SPM 10,000 ft TVD MUD WT = 10 ppg

Equivalent Circulating Density The APL while circulating has the same effect on bottom hole pressure as increasing the mud weight. This theoretical increase in mud weight is called the Equivalent Circulating Density or Equivalent Mud Weight. It can be calculated by using the following formula: _____APL(psi) __ + Original Mud Weight TVD x 0.052

Summary: Annular Pressure Losses are the pressure losses caused by the flow of fluid up the annulus and are the only losses in the system that affect BHP. Equivalent Circulating Density is the effective density at any depth created by the sum of the total hydrostatic plus the APL.

Exercise - Pressure Gradient? - Hydrostatic Pressure? 300 psi 600 psi 800 psi 1200 psi 450 psi - Pressure Gradient? - Hydrostatic Pressure? - Pump Pressure @ 40 spm? - A P L? - ECD at 40 SPM? 40 SPM MUD WT = 12 ppg MD = 9,550 ft TVD = 8,000 ft

EFFECTS ON PRESSURES

MUD WEIGHT CHANGE 2600 psi 80 spm Mud wt 10 ppg A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi. It is decided to increase the mud weight to 11 ppg. 80 spm Mud wt 10 ppg

MUD WEIGHT CHANGE 2860 psi 80 spm Mud wt 11 ppg It is a good drilling practice to calculate the new circulating pressure before changing the mud weight. The way we calculate this change in pressure is to use the following formula; New Mud ppg x Old psi. Old Mud ppg 11 ppg x 2600 = 2860psi 10 ppg The new pump pressure would be approximately 2860 psi. 2860 psi 80 spm Mud wt 11 ppg

Final Circulating Pressure The formula that was just used to calculate the pressure change due to a change in mud weight, is also the formula used to calculate the Final Circulating Pressure. Kill Mud wt x Slow circulating rate press . Old Mud wt

PUMP STROKE CHANGE 2600 psi A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi. It is decided to increase the pump speed from 80 spm to 100 spm. 80 spm Mud wt 10 ppg

PUMP STROKE CHANGE 4063 psi 100 spm Mud wt 10 ppg It is a good drilling practice to calculate the new circulating pressure before changing the pump speed. The way we calculate this change in pressure is to use the following formula; New SPM 2 Old psi x Old SPM 2600 x 100 spm 2 80 spm = 4063 psi The new pump pressure would be approximately 4063 psi. 4063 psi 100 spm Mud wt 10 ppg

Preparation and Prevention

Preparation and Prevention Barite and Mud chemical stocks Equipment line up for shut-in Slow circulating rates M A A S P Well Control Drills Flow Checks Safety Valves and Float Valves

FLOWPATH LINE UP FOR HARD SHUT IN

FLOWPATH HARD SHUT IN 2 3 4 1 5 Pick off bottom and position string Stop pumps & Rotation Close BOP (Ram or Annular) Open hydraulic side outlet valve Observe pressure 1 2 3 4 5

FLOWPATH LINE UP FOR SOFT SHUT IN

FLOWPATH SOFT SHUT IN 2 3 4 1 5 6 Pick off bottom and position string Stop pumps & Rotation Open hydraulic side outlet valve Close BOP (Ram or Annular) Close remote hydraulic choke Observe pressure 1 2 3 4 5 6

Slow Circulating Rate A Slow Circulating Rate ( SCR) is the reduced circulating pump rate that is used when circulating out a kick. It is called Dynamic Pressure Losses ( PL ) on the kick sheet

Slow Circulating Rate Well Control Operations are conducted at reduced circulating rates in order to: Minimise Excess of annulus pressure Allows for more controlled choke adjustments Allows for the weighting up and degassing of the mud and disposal of the influx Reduce the chance of choke erosion Reduce risk of over pressuring system if plugging occurs

SCR’s pressure for each pump will be taken: Slow Circulating Rate SCR’s pressure for each pump will be taken: If practical, at the beginning of every tour Any time the mud properties are changed When a bit nozzle is changed. When the BHA is changed. As soon as possible after bottoms-up from any trip At least every 1000 feet (305m) of new hole

Slow Circulating Rate A minimum of 2 (two) circulating rates should be obtained for all pumps. The pressure must be recorded using the gauges that will be used during well kill operations The SCR pressure will be recorded on the IADC report

Formation Strength Test or LOT A leak off test (LOT) determines the pressure at which the formation begins to take fluid. This test is conducted after drilling out about 10 to 15 ft of new hole below the shoe. Such a test will establish the strength of the formation and the integrity of the cement job at the shoe. The test pressure should not exceed 70% of the minimum yield of the weakest casing.

L O T Use a high pressure, low volume pump (0.25 - 0.5 bbl/min.) such as a cement pump or a test pump using intermittent or continuous method of pumping. Rig pumps are not suitable to perform leak off tests. The objective of the above test is not to fracture the formation, but rather to identify the “formation intake pressure”. This “intake pressure” is identified as that point where a deviation occurs between the trends of the final pump pressure curve and the static pressure curve. Once the formation intake pressure has been reached, further pumping should be avoided.

L O T The total pressure applied at the shoe is the sum of the surface pressure from the pump and the hydrostatic pressure for the shoe depth. This total pressure is applied to the formation. Surface Casing Pressure + Hydrostatic Pressure = Pressure at Shoe

L O T This total pressure is applied to the formation. 720 psi 720 psi + 1498 psi 9.6 ppg 3,000’ 2218 psi This total pressure is applied to the formation.

The Maximum Available Fluid Density (MAMW). This is the total pressure, represented as fluid density, above which leak off or formation damage may occurs with no pressure on surface. 2218 psi 0 psi 3,000’ MAMW = 14.2 ppg MAMW= 2218 3000 x 0.052

The fracture gradient of the formation will be: Fracture gradient = MAMW x 0.052 Fracture Gradient = 14.2 x 0.052 = 0.7384 psi/ft therefore: MAMW = Fracture Gradient / 0.052 2218 psi 0 psi 3,000’

Maximum Allowable Annular Surface pressure M A A S P MAASP is defined as the surface pressure which, when added to the hydrostatic pressure of the existing mud column, results in formation breakdown at the weakest point in the well. This value is based on the Leak Off Test data.

On Kill Sheet Write leak off test pressure here Write mud weight used for the test Calculate maximum allow mudweight and Insert here Calculate current MAASP and insert here

Drills Pit drill Trip drill Abandonement drill Strip drill

Actions Upon Taking a Kick

Causes for the Loss of Primary Well Control Kick Size and Severity Kick Detection Recording Pressures Drilling With Oil Base Mud Hard Shut-in Soft Shut-in Height and Gradient of a Kick

Causes for the loss of Primary Well Control Failure to Fill The Hole Properly While Tripping Swabbing / Surging High pulling speed Mud properties Tight annulus clearance Well Geometry Formation Properties Lost Circulation Insufficient Drilling Fluid Density ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Kick Size and Severity Minimizing kick size is fundamental for the safety of a Well Control operation.Smaller Kicks: Provide lower choke or annulus pressure both upon initial closure and later when the kick is circulated to the choke. Controllable Parameters: You can influence on: Degree of underbalance Mud Weight Length of reservoir exposed ROP + Kick detection time Time well remains underbalanced Kick detection + shut-in time Wellbore diameter Hole size Non-controllable Parameters Formation permeability and type of influx

Kick Detection While Drilling: Drilling breaks: They will be flow checked. Circulating B/up is advisable if F/C is negative. Tool pusher must be informed for all. Increase in flow rate: First positive indicator. Increase in pit volume: Positive indicator. Anyone influencing the active system must communicate with the Driller. Variation in Pump speed and Pressure: (“U-tube”) Well flowing during a Connection: ECD to ESD Change of drilling fluid properties: Gas cut or fluid contaminated. While Tripping: Improper fill-up: swabbing or surging ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Shut- in Procedure: HARD SHUT-IN Stop rotation Pick up the drill string to shut-in position (subsea to hang off position) Stop the pump Flow check If the well flows Close BOP Open remote control choke line valve Notify Tool Pusher and OIM Record time, SIDPP, SICP and pit gain

Shut- in Procedure: SOFT SHUT-IN Stop rotation Pick up the drill string to shut-in position (Subsea to hang off position) Stop the pump Flow check If the well flows Open remote control choke line valve Close BOP Close choke Notify Tool Pusher Record time, SIDPP, SICP and pit gain

Close-in Methods specified by American Petroleum Institute Soft close-in procedure For a soft close-in, a choke is left open at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blow out preventer. When the soft close-in procedure is selected for closing in a well the: 1 choke line valve is opened. 2 Blow out preventer is closed. 3 Choke is closed. This procedure allows the choke to be closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure. Hard close-in procedure For a hard close-in, the chokes remain closed at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system with the exemption of the choke(s) itself and one choke line valve located near the blow out preventer stack. When the hard close-in procedure is selected for closing in a well, the blow out preventer is closed. If the casing pressure cannot be measured at the well head, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold. This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the well bore.

Surface Pressure After Shut-in

OIL BASE MUD

Drilling with OBM

Gas Influx in WBM or in OBM Water Base Mud Easier to detect Higher migration rate Gas stay as a separate phase On bottom bigger kick size Higher casing pressure Expansion: - Slow first then Fast Oil Base Mud More difficult to detect Lower migration rate Gas go into solution On bottom smaller kick size Smaller casing pressure Expansion: - none first then very fast at the bubble point

Height and Gradient of a Kick

Well Kill Techniques

Driller’s Method Wait and Weight Method Volumetric Method

Well Kill Techniques

Driller’s Method : 1 st Circulation The original mud weight is used to circulate the influx - Reset the stroke counter. - Bring the pump up to kill speed while holding the casing pressure constant. - Maintain DP pressure constant until the influx is circulated out from the well BHP

Driller’s Method : 1 st Circulation The maximum shoe pressure is when the top of the influx reaches the shoe

Driller’s Method : 1 st Circulation When the influx is passing the casing shoe, the shoe pressure will decrease.

Driller’s Method : 1 st Circulation When the influx is above the casing shoe, the shoe pressure will remain constant.

Driller’s Method : 1 st Circulation - Surface casing pressure is increasing as the influx is circulated up the well. - Pit volume is raising.

Driller’s Method : 1 st Circulation - The maximum surface casing pressure is reached when the top of the influx is at surface. - It will be the maximum increase in pit level.

Driller’s Method : 1 st Circulation - As the influx is passing through the choke, the surface casing pressure will decrease. - The pit volume will decrease.

Driller’s Method : 1 st Circulation If all the influx is successfully circulated from the well and the pump is stopped, SIDPP = SICP

Driller’s Method : 2 nd Circulation - Line up the kill mud. - Reset the stroke counter. - Bring the pump up to kill speed while holding the casing pressure constant. - Reset the stroke counter after pumping the surface line volume. - Keep the casing pressure constant until KMW reach the bit. ( Or follow the calculated DP pressure drop schedule from ICP to FCP.) Pit volume has increased due to the weighting material added in the system.

Driller’s Method : 2 nd Circulation When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

First Circulation Drill Pipe Casing Driller’s Method Driller’s Method ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Second Circulation Drill Pipe Casing Driller’s Method Driller’s Method ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Driller’s Method Advantages: Disadvantages: - Can start circulating right away - Able to remove influx even if not enough barite on board - Less chance of gas migration - Less calculation Disadvantages: - Higher surface pressure - In certain situation, higher shoe pressure - Two circulation, more time through the choke

Wait and Weight -The kill mud weight is used to circulate the influx -Reset the stroke counter - Bring the pump up to kill speed while Holding the casing pressure constant. - Reset the stroke counter after pumping the surface line volume. -Pump kill mud from surface to bit while following a calculated DP pressure drop schedule. BHP

Wait and Weight When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

One Circulation Only Wait & Weight Drill Pipe Wait & Weight Casing

Wait & Weight Method Advantages: Disadvantages: - Can generate lower pressure on formation near the casing shoe - In most situation generate less pressure on surface equipment - With a long open hole, less chance to induce losses - One circulation, less time spent circulating through the choke Disadvantages: - Longer waiting time prior to circulate the influx - Cutting could settle down and plug the annulus - Gas migration might become a problem - Need to have enough barite to increase the mud weight - More Calculations

Differences between W&W and Driller’s methods h'i h'i W & W Method Gas at Casing Shoe, kill mud in drill string hm hm Drillers Method Gas at Casing Shoe

Differences between W&W and Driller’s methods h'i h''i W & W Method Gas at Casing Shoe, Kill mud in annulus hm Drillers Method Gas at Casing Shoe hm hkm

Gas Behavior No gas expansion Free gas expansion No gas expansion Volume to bleed off to maintain BHP constant

Free Gas Expansion Gas may be swabbed into a well and remain at TD. The influx will expand as it moves up the annulus when circulation is started. The amount of expansion can easily be calculated. If undetected, free gas expansion can cause a serious well control problem.

Free Gas Expansion A column of 10,000ft of mud, Gm=0.5psi/ft compresses one barrel of gas at TD. The pressure in the gas is; 10,000 x 0.5 = 5,000 psi Multiply P x Vg to find the constant. D=10,000ft Gm = 0.5 psi/ft Gas D 10,000 P 5,000 Vg 1 5,000 CST

Free Gas Expansion The gas has risen so that the top of the bubble is at 5,000ft from the surface. The pressure in the gas is; 5,000 x 0.5 = 2,500 psi Using the constant, the volume of gas is found: 5,000 / 2,500 = 2 barrels D=5,000ft Gm = 0.5 psi/ft D 10,000 5,000 5,000 2,500 P Vg 1 2 5,000 5,000 PVg

Free Gas Expansion The top of the bubble is at 2,500ft from the surface. The pressure in the gas is; 2,500 x 0.5 = 1,250 psi The volume of gas is found: 5,000 / 1,250 = 4 barrels D=2,500ft Gm = 0.5 psi/ft D 10,000 5,000 2,500 P 5,000 2,500 1,250 Vg 1 2 4 PVg 5,000 5,000 5,000

Free Gas Expansion At 1,250ft from the surface. Pressure; 1,250 x 0.5 = 625 psi Volume of gas; 5,000 / 625 = 8 barrels D=1,250ft Gm = 0.5 psi/ft D P Vg PVg 10,000 5,000 1 2,500 2 1,250 4 625 8

Free Gas Expansion D P Vg PVg 10,000 5,000 1 2,500 2 1,250 4 625 8 Gm = 0.5 psi/ft D P Vg PVg 10,000 5,000 1 2,500 2 1,250 4 625 8 14.7 341

No Gas Expansion Gm = 0.52 psi/ft 0 psi 5,200 psi 1 bbls 10,000 ft 5,200 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1 bbl gain

No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 5,200 psi 6,500 psi 1 bbls 1 bbls 10,000 ft 5,200 psi 6,500 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1 bbl gain 1 bbl gain

No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 2,600 psi 5,200 psi 1 bbls 5,000 ft 7,500 ft 1 bbls 1 bbls 10,000 ft 5,200 psi 6,500 psi 7,800 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1 bbl gain 1 bbl gain 1 bbl gain

No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 2,600 psi 3,900 psi 1 bbls 1 bbls 5,000 ft 7,500 ft 1 bbls 1 bbls 10,000 ft 5,200 psi 6,500 psi 7,800 psi 9,100 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain

No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 2,600 psi 3,900 psi 1 bbls 2,500 ft 1 bbls 1 bbls 5,000 ft 7,500 ft 1 bbls 1 bbls 10,000 ft 5,200 psi 6,500 psi 7,800 psi 9,100 psi 10,400 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain

Volume to bleed off to keep BHP constant 500 psi 1800 psi 0 ft 2,500 ft 5,000 ft 5700 psi 4400 psi 1.3bbls 7,500 ft 1bbls P1V1 = P2V2 V2 = 5700 x 1 / 4400 V2 = 1.29 bbls 2500 x .52 = 1300 psi 1 bbls 10,000 ft 5,700 psi 7000 psi 5,700 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1 bbl gain 1 bbl gain 1.3 bbl gain

Volume to bleed off to keep BHP constant 500 psi 1800 psi 0 ft 2,500 ft 3100 psi 4400 psi 1.84bbls 5,000 ft 1.3bbls P1V1 = P3V3 V3 = 5700 x 1 / 3100 V3 = 1.84 bbls 1.3 bbls 7,500 ft 5000 x .52 = 2600 psi 10,000 ft 5,700 psi 7,000 psi 5,700 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1.3 bbl gain 1.3 bbl gain 1.84 bbl gain

Volume to bleed off to keep BHP constant 500 psi 1800 psi 0 ft 3100 psi 1800 psi 2,500 ft 1.8bbls 3.16bbls P1V1 = P4V4 V4 = 5700 x 1 / 1800 V4 = 3.16 bbls 1.8 bbls 5,000 ft 7,500 ft 7500 x .52 = 3900 psi 10,000 ft 5,700 psi 7,000 psi 5,700 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 1.84 bbl gain 1.84 bbl gain 3.16 bbl gain

Volume to bleed off to keep BHP constant 500 psi 1800 psi 1800 psi 500 psi 0 ft P1V1 = P5V5 V5 = 5700 x 1 / 500 V5 = 11.4 bbls 3.16 bbls 11.4bbls 2,500 ft 3.16 bbls 5,000 ft 7,500 ft 10000 x .52 = 5200 psi 10,000 ft 5,700 psi 7,000 psi 5,700 psi ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Gm = 0.52 psi/ft 3.16 bbl gain 3.16 bbl gain 11.4 bbl gain

WELL # 1 HOLE SIZE HOLE DEPTH TVD/MD CASING 9-5/8” TVD/MD DRILL PIPE CAP. HEAVY WALL DRILL PIPE CAPACITY DRILL COLLARS 6-1/4” DRILLING FLUID DENSITY CAPACITY OPEN HOLE/COLLARS CAPACITY OPEN HOLE/DRILL PIPE-HWDP CAPACITY CASING/DRILL PIPE FRACTURE FLUID DENSITY SIDPP SICP PUMP DISPLACEMENT RRCP 30 SPM PIT GAIN 8-1/2 INCH 11536 FEET 9875 FEET 0.01741 BBL/FEET 600 FEET 0.00874 BBL/FEET 880 FEET 0.00492 BBL/FEET 14.0 PPG 0.03221 BBL/FEET 0.04470 BBL/FEET 0.04891 BBL/FEET 16.9 PPG 530 PSI 700 PSI 0.1019 BBL/STRK 650 PSI 10.0 BBL DRILLERS METHOD: The well drilled is a vertical well and the well has reach a total depth of 11536 ft where a overpressure zone is penetrated resulting in a 10 bbl influx into the wellbore. The well was shut in using Hard Shut In method on Upper Pipe Rams and the above mentioned information were obtained and Kill Sheet filled out for using Drillers Method to circulate out the influx and regain control over the well. Internal strokes from surface to bit: 1812 strokes Total annulus from bit to surface: 5360 strokes Open hole from bit to shoe: 620 strokes Kill fluid density: 14.9 ppg Initial circulation pressure 1180 psi Final circulation pressure: 692 psi Initial MAASP with drilling fluid density: 1489 psi New MAASP with kill fluid density: 1027 psi Height of influx: 310 ft Total circulation time w/ 30 spm: 239 min

DRILLERS METHOD SHUTTING IN WELL 1st CIRCULATION DP CSG 1489 530 700 1489 SHUTTING IN WELL MAASP 530 700 O C DRILLERS METHOD: While drilling at 11536 ft a flow increase was observed and the well shut in using Hard Shut In method: Position drill string. Shut down pumps and rotating. Close Upper Pipe Rams. Open Hyd. Side Outlet Valve. Observe pressure. DP pressure stabilized at 530 psi. CSG pressure stabilized at 700 psi. BHP increased from Ph 8398 psi to 8928 psi. ( Ph + SIDPP) Shoe pressure increased from Ph 7189 psi to 7889 psi. ( Phshoe + SICP) Pit gain measured to 10 bbl. 7189 7889 Ph= 8398 psi Pf= 8928 psi

DRILLERS METHOD REACHING ICP KEEP CONSTANT CASING PRESSURE 1st CIRCULATION DP CSG 30 1489 REACHING ICP KEEP CONSTANT CASING PRESSURE WHILE BRINGING PUMPS UP PUMPS UP AND PRESSURE STABILISED DRILL PIPE PRESSURE 22 MAASP 1180 700 O C DRILLERS METHOD: While keeping constant casing pressure the pumps are slowly brought up to slow circulating rate, in this case 30 SPM. When the pumps are running at 30 SPM and pressures have stabilized the ICP pressure on the drill pipe gauge is keep constant. ICP= SIDPP + RRCP 530 psi + 650 psi = 1180 psi Shoe pressure = Phshoe + SICP 7189 psi + 700 psi = 7889 psi MAASP = Max Shoe Pressure - Phshoe 8678 psi - 7189 psi = 1489 psi 7889 BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD GAS IN OPEN HOLE CONSTANT DRILL PIPE PRESSURE 1st CIRCULATION DP CSG 30 GAS IN OPEN HOLE CONSTANT DRILL PIPE PRESSURE GAS EXPANDING CASING PRESSURE INCREASE SHOE PRESSURE MAASP CONSTANT 1489 310 MAASP 1180 740 O C 7929 DRILLERS METHOD: Situation after pumping 310 strokes: Drill Pipe Pressure is kept constant while gas is being pumped up through the open hole section. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 740 psi Shoe pressure is increasing with same value as the casing pressure. Shoe P = Phshoe + Csg P 7929 psi MAASP remains constant due to no change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD GAS REACH SHOE CONSTANT DRILL PIPE PRESSURE 1st CIRCULATION DP CSG 30 GAS REACH SHOE CONSTANT DRILL PIPE PRESSURE GAS EXPANDING CASING PRESSURE INCREASE SHOE PRESSURE INCREASE TO MAX MAASP CONSTANT 1489 470 MAASP 1180 775 O C DRILLERS METHOD: Situation after pumping 470 strokes: Drill Pipe Pressure is kept constant while gas is being pumped up through the open hole section and the top of the gas bubble reach the shoe. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 775 psi Shoe pressure is increasing with same value as the casing pressure. Shoe P = Phshoe + Csg P 7964 psi MAASP remains constant due to no change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1489 psi 7964 BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD GAS MOVES INSIDE CASING CONSTANT DRILL PIPE PRESSURE 1st CIRCULATION DP CSG 30 GAS MOVES INSIDE CASING CONSTANT DRILL PIPE PRESSURE GAS EXPANDING CASING PRESSURE INCREASE SHOE PRESSURE DECREASE MAASP INCREASING 1685 620 MAASP 1180 785 O C 7718 DRILLERS METHOD: Situation after pumping 620 strokes: Drill Pipe Pressure is kept constant while gas is being pumped from the open hole section until all the gas is inside the casing so the open hole section is displaced to original drilling fluid. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 785 psi Shoe pressure is constantly decreasing from gas reach the shoe until all gas is inside casing. Shoe P = BHP - Phopen hole 7718 psi MAASP start increasing from the first gas enter the casing due to change in Ph inside the casing MAASP = Max Shoe Pressure - Phshoe 1685 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD GAS MOVING INSIDE CASING CONSTANT DRILL PIPE PRESSURE 1st CIRCULATION DP CSG 30 GAS MOVING INSIDE CASING CONSTANT DRILL PIPE PRESSURE GAS EXPANDING CASING PRESSURE INCREASE SHOE PRESSURE MAASP INCREASING 2020 2300 MAASP 1180 1120 O C 7718 DRILLERS METHOD: Situation after pumping 2300 strokes: Drill Pipe Pressure is kept constant while gas is being pumped up inside the casing between shoe and surface. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 1120 psi Shoe pressure remains constant from the moment all gas is inside the casing. Shoe P = BHP - Phopen hole 7718 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 2020 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD GAS REACH CHOKE CONSTANT DRILL PIPE PRESSURE 1st CIRCULATION DP CSG 30 GAS REACH CHOKE CONSTANT DRILL PIPE PRESSURE GAS EXPANDING CASING PRESSURE INCREASE TO MAX SHOE PRESSURE MAASP 2480 4800 MAASP 1180 1580 O C DRILLERS METHOD: Situation after pumping 4800 strokes: Drill Pipe Pressure is kept constant while gas is being pumped up inside the casing and the top of the gas bubble reach the choke. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid and when top of the gas bubble reach the choke casing pressure is increased to max. CSG P = BHP - (Phmud + Phgas) 1580 psi Shoe pressure remains constant from the moment all gas is inside the casing. Shoe P = BHP - Phopen hole 7718 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing and will reach max value when gas at choke. MAASP = Max Shoe Pressure - Phshoe 2480 psi 7718 BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD GAS OUT OF WELL CONSTANT DRILL PIPE PRESSURE 1st CIRCULATION DP CSG 30 GAS OUT OF WELL CONSTANT DRILL PIPE PRESSURE CASING PRESSURE DECREASING TO SIDPP SHOE PRESSURE MAASP DECREASING TO ORIGINAL VALUE 1489 5400 MAASP 1180 530 O C 7718 DRILLERS METHOD: Situation after pumping 5400 strokes: Drill Pipe Pressure is kept constant while gas is being pumped out of the well through the choke. Casing pressure decreasing while drilling fluid is displacing gas in the well bore and will reach SIDPP when all the gas is out of the well. CSG P = BHP - Phmud 530 psi Shoe pressure remains constant while the gas is displaced from the well bore due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7718 psi MAASP decreasing with same value as the Casing Pressure and will reach initial MAASP when the annulus is displaced to original drilling fluid. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD START PUMPING KILL MUD 14.9 PPG CASING PRESSURE 2nd CIRCULATION DP CSG 30 START PUMPING KILL MUD 14.9 PPG CASING PRESSURE CONSTANT SHOE PRESSURE MAASP CONSTANT 1489 5400 MAASP 1180 530 O C 7718 DRILLERS METHOD: Kill mud is being mixed to 14.9 ppg and 2nd circulation is started. Casing pressure is kept constant while kill fluid fills the drill string. CSG P = BHP - Phmud 530 psi Drillpipe pressure decreasing while kill fluid fills the drill string. DP P = RRCP + (BHP - Phmud) Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7718 psi MAASP remains constant while kill mud fills the drill string. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD KILL FLUID INSIDE DRILL PIPE CASING PRESSURE CONSTANT 2nd CIRCULATION DP CSG 30 KILL FLUID INSIDE DRILL PIPE CASING PRESSURE CONSTANT DRILL PIPE PRESSURE DECREASING SHOE PRESSURE MAASP CONSTANT 1489 6306 MAASP 936 530 O C 7718 DRILLERS METHOD: Situation after pumping 6306 strokes: Casing pressure is kept constant while kill fluid fills the drill string. CSG P = BHP - Phmud 530 psi Drillpipe pressure decreasing while kill fluid fills the drill string. DP P = RRCP + (BHP - Phmud) 936 psi Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7718 psi MAASP remains constant while kill mud fills the drill string. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD KILL MUD REACH BIT CONSTANT CASING PRESSURE 2nd CIRCULATION DP CSG 30 KILL MUD REACH BIT CONSTANT CASING PRESSURE DRILL PIPE PRESSURE DECREASING TO FCP SHOE PRESSURE CONSTANT MAASP CONSTANT 1489 7212 MAASP 692 530 O C 7718 DRILLERS METHOD: Situation after pumping 7212 strokes: Kill fluid reach the bit. Casing pressure is kept constant while kill fluid fills the drill string. CSG P = BHP - Phmud 530 psi Drillpipe pressure decreasing while kill fluid fills the drill string and when kill fluid reach the bit pressure is FCP or RRCP w/14.9 ppg mud. DP P = RRCP w/14.9 ppg 692 psi Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7718 psi MAASP remains constant while kill mud fills the drill string. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD KILL MUD REACH SHOE DRILL PIPE PRESSURE CONSTANT 2nd CIRCULATION DP CSG 30 KILL MUD REACH SHOE DRILL PIPE PRESSURE CONSTANT CASING PRESSURE DECREASING SHOE PRESSURE MAASP CONSTANT 1489 7832 MAASP 692 469 O C 7657 DRILLERS METHOD: Situation after pumping 7832 strokes: Kill fluid at shoe. Drillpipe pressure is kept constant while kill fluid displace original mud in annulus. DP P = RRCP w/14.9 ppg 692 psi Casing pressure decreasing as kill fluid moves up the annulus to the shoe. CSG P = BHP - Phmud 469 psi Shoe pressure decreasing as kill fluid moves up the annulus to the shoe with same value as the decrease in Csg P. Shoe P = BHP - Phopen hole 7657 psi MAASP remains constant while kill fluid moves up the annulus to the shoe. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD KILL MUD INSIDE CASING DRILL PIPE PRESSURE CONSTANT 2nd CIRCULATION DP CSG 30 KILL MUD INSIDE CASING DRILL PIPE PRESSURE CONSTANT CASING PRESSURE DECREASING SHOE PRESSURE MAASP DECREASING 1253 10202 MAASP 692 233 O C 7657 DRILLERS METHOD: Situation after pumping 10202 strokes: Kill fluid inside casing. Drillpipe pressure is kept constant while kill fluid displace original mud in annulus. DP P = RRCP w/14.9 ppg 692 psi Casing pressure decreasing as kill fluid moves up the annulus. CSG P = BHP - Phmud 233 psi Shoe pressure remains constant while kill fluid is displacing original mud inside the casing due to no change in Ph open hole. Shoe P = BHP - Phopen hole 7657 psi MAASP decreasing as kill fluid is displacing original mud inside the casing with same value as the drop in casing pressure. MAASP = Max Shoe Pressure - Phshoe 1253 psi BHP= 8928 PSI Pf= 8928 psi

DRILLERS METHOD KILL MUD AT SURFACE DRILL PIPE PRESSURE CONSTANT 2nd CIRCULATION DP CSG 30 KILL MUD AT SURFACE DRILL PIPE PRESSURE CONSTANT CASING PRESSURE DECREASING TO ZERO SHOE PRESSURE MAASP DECREASING TO NEW MAASP w/KMW 1020 12600 MAASP 692 O C 7657 DRILLERS METHOD: Situation after pumping 12600 strokes: Kill fluid at the choke. Drillpipe pressure is kept constant while kill fluid displace original mud in annulus. DP P = RRCP w/14.9 ppg 692 psi Casing pressure decreasing as kill fluid moves up the annulus and will reach 0 psi when kill fluid reach the choke. CSG P = BHP - Phmud 0 psi Shoe pressure remains constant while kill fluid is displacing original mud inside the casing due to no change in Ph open hole. Shoe P = BHP - Phopen hole 7657 psi MAASP decreasing as kill fluid is displacing original mud inside the casing with same value as the drop in casing pressure. MAASP = Max Shoe Pressure - Phshoe 1020 psi BHP= 8928 PSI Pf= 8928 psi

WELL # 1 HOLE SIZE HOLE DEPTH TVD/MD CASING 9-5/8” TVD/MD DRILL PIPE CAP. HEAVY WALL DRILL PIPE CAPACITY DRILL COLLARS 6-1/4” DRILLING FLUID DENSITY CAPACITY OPEN HOLE/COLLARS CAPACITY OPEN HOLE/DRILL PIPE-HWDP CAPACITY CASING/DRILL PIPE FRACTURE FLUID DENSITY SIDPP SICP PUMP DISPLACEMENT RRCP 30 SPM PIT GAIN 8-1/2 INCH 11536 FEET 9875 FEET 0.01741 BBL/FEET 600 FEET 0.00874 BBL/FEET 880 FEET 0.00492 BBL/FEET 14.0 PPG 0.03221 BBL/FEET 0.04470 BBL/FEET 0.04891 BBL/FEET 16.9 PPG 530 PSI 700 PSI 0.1019 BBL/STRK 650 PSI 10.0 BBL WAIT & WEIGHT METHOD: The well drilled is a vertical well and the well has reach a total depth of 11536 ft where a overpressure zone is penetrated resulting in a 10 bbl influx into the wellbore. The well was shut in using Hard Shut In method on Upper Pipe Rams and the above mentioned information were obtained and Kill Sheet filled out for using W&W Method to circulate out the influx and regain control over the well. Internal strokes from surface to bit: 1812 strokes Total annulus from bit to surface: 5360 strokes Open hole from bit to shoe: 620 strokes Kill fluid density: 14.9 ppg Initial circulation pressure 1180 psi Final circulation pressure: 692 psi Initial MAASP with drilling fluid density: 1489 psi New MAASP with kill fluid density: 1027 psi Height of influx: 310 ft Total circulation time w/ 30 spm: 239 min

WAIT & WEIGHT METHOD SHUTTING IN WELL MIXING KILL MUD 14.9 PPG DP CSG 1489 SHUTTING IN WELL MIXING KILL MUD 14.9 PPG MAASP 530 700 O C 7189 7889 WAIT & WEIGHT METHOD: While drilling at 11536 ft a flow increase was observed and the well shut in using Hard Shut In method: Position drill string. Shut down pumps and rotating. Close Upper Pipe Rams. Open Hyd. Side Outlet Valve. Observe pressure. DP pressure stabilized at 530 psi. CSG pressure stabilized at 700 psi. BHP increased from Ph 8398 psi to 8928 psi. ( Ph + SIDPP) Shoe pressure increased from Ph 7189 psi to 7889 psi. ( Phshoe + SICP) Pit gain measured to 10 bbl. Ph= 8398 psi Pf= 8928 psi

WAIT & WEIGHT METHOD REACHING ICP KEEP CONSTANT CASING PRESSURE DP CSG 30 REACHING ICP KEEP CONSTANT CASING PRESSURE WHILE BRINGING PUMPS UP PUMPS UP AND PRESSURE STABILISED KEEP DRILL PIPE PRESSURE ON SCHEDULE 1489 22 MAASP 1180 700 O C 7889 WAIT & WEIGHT METHOD: While keeping constant casing pressure the pumps are slowly brought up to slow circulating rate, in this case 30 SPM. When the pumps are running at 30 SPM and pressures have stabilized change to ICP and then keep DP pressure on schedule. ICP= SIDPP + RRCP 530 psi + 650 psi = 1180 psi Shoe pressure = Phshoe + SICP 7189 psi + 700 psi = 7889 psi MAASP = Max Shoe Pressure - Phshoe 8678 psi - 7189 psi = 1489 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD GAS IN OPEN HOLE DRILL PIPE PRESSURE DECREASING DP CSG 30 GAS IN OPEN HOLE DRILL PIPE PRESSURE DECREASING CASING PRESSURE INCREASING GAS EXPANDING SHOE PRESSURE MAASP CONSTANT 1489 310 MAASP 1097 740 O C 7929 WAIT & WEIGHT METHOD: Situation after pumping 310 strokes: The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped. DP P = ICP - (310 x 27) 1097 psi 100 Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 740 psi Shoe pressure is increasing with same value as the casing pressure. Shoe P = Phshoe + Csg P 7929 psi MAASP remains constant due to no change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD GAS REACH SHOE DRILL PIPE PRESSURE DECREASING DP CSG 30 GAS REACH SHOE DRILL PIPE PRESSURE DECREASING CASING PRESSURE INCREASING GAS EXPANDING SHOE PRESSURE INCREASE TO MAX MAASP CONSTANT 1489 470 MAASP 1053 775 O C 7964 WAIT & WEIGHT METHOD: Situation after pumping 470 strokes: The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped. DP P = ICP - (470 x 27) 1053 psi 100 Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 775 psi Shoe pressure is increasing with same value as the casing pressure and reach max. value when gas reach the shoe. Shoe P = Phshoe + Csg P 7964 psi MAASP remains constant due to no change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1489 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD GAS MOVES INSIDE CASING DRILL PIPE PRESSURE DP CSG 30 GAS MOVES INSIDE CASING DRILL PIPE PRESSURE DECREASING CASING PRESSURE INCREASING GAS EXPANDING SHOE PRESSURE MAASP INCREASING 1685 620 MAASP 1013 785 O C 7718 WAIT & WEIGHT METHOD: Situation after pumping 620 strokes: The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped. DP P = ICP - (620 x 27) 1013 psi 100 Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 785 psi Shoe pressure is decreasing while gas moves from below the shoe until all gas inside the casing. Shoe P = BHP - Phopen hole 7718 psi MAASP start increasing from the first gas enter the casing due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1685 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD KILL MUD AT BIT GAS INSIDE CASING DP CSG 30 KILL MUD AT BIT GAS INSIDE CASING DRILL PIPE PRESSURE DECREASE TO FCP CASING PRESSURE INCREASING GAS EXPANDING SHOE PRESSURE CONSTANT MAASP INCREASING 1950 1812 MAASP 692 1050 O C 7718 WAIT & WEIGHT METHOD: Situation after pumping 1812 strokes: The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped and reach FCP when kill fluid at bit. DP P = ICP - (1812 x 27) 692 psi 100 Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 1050 psi Shoe pressure constant due to no change in Phopen hole Shoe P = BHP - Phopen hole 7718 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1950 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD KILL MUD AT SHOE GAS INSIDE CASING DP CSG 30 KILL MUD AT SHOE GAS INSIDE CASING DRILL PIPE PRESSURE CONSTANT CASING PRESSURE INCREASING GAS EXPANDING SHOE PRESSURE DECREASING MAASP INCREASING 1980 2432 MAASP 692 1080 O C 7641 WAIT & WEIGHT METHOD: Situation after pumping 2432 strokes: The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure constant at FCP after kill fluid reach the bit. DP P = FCP 692 psi Casing pressure increasing due to the expanding gas is displacing drilling fluid, but slower due to kill fluid is displacing original mud. CSG P = BHP - (Phmud + Phgas + Phkill mud) 1080 psi Shoe pressure decreasing as kill fluid moves up the annulus to the shoe. Shoe P = BHP - Phopen hole 7641 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1980 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD KILL MUD INSIDE CASING GAS REACH CHOKE DP CSG 30 KILL MUD INSIDE CASING GAS REACH CHOKE DRILL PIPE PRESSURE CONSTANT CASING PRESSURE INCREASING GAS EXPANDING SHOE PRESSURE MAASP INCREASING 2178 4800 MAASP 692 1278 O C 7641 WAIT & WEIGHT METHOD: Situation after pumping 4800 strokes: The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure constant at FCP after kill fluid reach the bit. DP P = FCP 692 psi Casing pressure increasing due to the expanding gas is displacing drilling fluid, but slower due to kill fluid is displacing original mud. CSG P = BHP - (Phmud + Phgas + Phkill mud) 1278 psi Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7641 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 2178 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD KILL MUD INSIDE CASING GAS OUT OF WELL DP CSG 30 KILL MUD INSIDE CASING GAS OUT OF WELL DRILL PIPE PRESSURE CONSTANT CASING PRESSURE DECREASING SHOE PRESSURE MAASP DECREASING 1204 5360 MAASP 692 180 O C 7641 WAIT & WEIGHT METHOD: Situation after pumping 5360 strokes: Drill Pipe Pressure constant at FCP after kill fluid reach the bit. DP P = FCP 692 psi Casing pressure decreasing while gas is displaced out of the well bore. CSG P = BHP - (Phmud + Phkill mud) 180 psi Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7641 psi MAASP decreasing while gas is displaced out of the well bore. MAASP = Max Shoe Pressure - Phshoe 1204 psi BHP= 8928 PSI Pf= 8928 psi

WAIT & WEIGHT METHOD KILL MUD AT SURFACE DRILL PIPE PRESSURE CONSTANT DP CSG 30 KILL MUD AT SURFACE DRILL PIPE PRESSURE CONSTANT CASING PRESSURE DECREASING TO ZERO SHOE PRESSURE MAASP DECREASING TO NEW MMASP w/KMW 1027 7200 MAASP 692 O C 7641 WAIT & WEIGHT METHOD: Situation after pumping 7200 strokes: Drill Pipe Pressure constant at FCP after kill fluid reach the bit. DP P = FCP 692 psi Casing pressure decreasing to 0 psi while kill fluid displace original mud out of the well bore. CSG P = BHP - Phkill mud 0 psi Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7641 psi MAASP decreasing while kill fluid displace original mud out of the well bore. MAASP = Max Shoe Pressure - Phshoe 1027 psi BHP= 8928 PSI Pf= 8928 psi

WELL # 1 HOLE SIZE HOLE DEPTH TVD/MD CASING 9-5/8” TVD/MD DRILL PIPE CAP. HEAVY WALL DRILL PIPE CAPACITY DRILL COLLARS 6-1/4” DRILLING FLUID DENSITY CAPACITY OPEN HOLE/COLLARS CAPACITY OPEN HOLE/DRILL PIPE-HWDP CAPACITY CASING/DRILL PIPE FRACTURE FLUID DENSITY SIDPP SICP PUMP DISPLACEMENT RRCP 30 SPM PIT GAIN 8-1/2 INCH 11536 FEET 9875 FEET 0.01741 BBL/FEET 600 FEET 0.00874 BBL/FEET 880 FEET 0.00492 BBL/FEET 14.0 PPG 0.03221 BBL/FEET 0.04470 BBL/FEET 0.04891 BBL/FEET 16.9 PPG 530 PSI 700 PSI 0.1019 BBL/STRK 650 PSI 10.0 BBL

GMD = ------------------------- GMR = ------------------------- VOLUMETRIC METHOD MIGRATION DISTANCE GMD = ------------------------- P2 - P1 MUD GRADIENT MIGRATION RATE/HRS GMR = ------------------------- GMD x 60 T2 - T1

VOLUMETRIC METHOD KEY POINT: Ph Ph EVERY BARREL OF MUD IN THE WELLBORE REPRESENT A CERTAIN AMOUNT OF HYDROSTATIC PRESSURE Ph Ph

VOLUMETRIC METHOD CHOKE PRESSURE PRESSURE/BARREL WORKING RANGE 50 PSI SICP + SAFETY FACTOR + WORKING RANGE PRESSURE/BARREL PSI/BBL = ---------------------------- 14.88 = ---------------------------- WORKING RANGE 50 PSI VOLUME TO BLEED =-------------------- 3.36 BBL =----------------------------- MUD GRADIENT W.R. CAPACITY PSI/BBL 14 x 0.052 50 0.04891 14.88

VOLUMETRIC METHOD PA P2 - P1 GMD = -------------------------- MWG 10000 ft 12.5 ppg 300 psi 6500 psi GAS GMD = -------------------------- GMR = -------------------------- Where: GMD = Gas migration distance MWG = Mud gradient P1 = Surface pressure at time T1 P2 = Surface pressure at time T2 GMR = Gas migration rate ( feet per hour) T1 = Time 1 (hour) T2 = Time 2 (hour) P2 - P1 MWG GMD T2 - T1

VOLUMETRIC METHOD PA P2 - P1 GMD = -------------------------- MWG 10000 ft 12.5 ppg 300 psi 6500 psi GAS GMD = -------------------------- GMR = -------------------------- Where: GMD = Gas migration distance MWG = Mud gradient P1 = Surface pressure at time T1 P2 = Surface pressure at time T2 GMR = Gas migration rate ( feet per hour) T1 = Time 1 (hour) T2 = Time 2 (hour) P2 - P1 MWG GMD T2 - T1

VOLUMETRIC METHOD

VOLUMETRIC METHOD PA Pa BHP BOP KILL LINE GAS S I C P P1 P3 Vm HALLIBURTON BOP PA KILL LINE GAS S I C P P1 P3 Vm BLEED OFF LUBRICATE 1 2 3 4 5 6 BHP Pa

VOLUMETRIC METHOD BLEED OFF LUBRICATE Gas bubble pressure Bottom hole pressure Annular pressure Drill pipe pressure TIME PRESSURE

Bull heading Involves forcing formation fluids back into the formation using surface hydraulics Usually considered if: 1 Formation fluid cannot be safely handled on surface (eg with H2S) 2 If anticipated formation pressures exceed what can be safely handled Method usually employed as a last resort

Tertiary well control Methods Cement Plug Barite plug Gunk plug

Shallow Gas Evaluation & Planning Drill a pilot hole Heavy mud in ready(1-2 ppg higher) Controlled ROP Use of Viscous pills instead of weighted pills High circulation rates Float in string

Diverting Shallow Gas Open vent line Close Diverter Switch suctions to heavy mud Increase pump speed to maximum Circulate heavy mud round Flow check If still positive continue pumping.( if mud finished continue with water) INTERLOCKED

Well Control Complications

Well Control Complications

WELL CONTROL COMPLICATIONS

Lost Circulation Formation breakdown Fractures and Fissures Bad cement

Loss Circulation Categories: Seepage losses (<2bbl/Hr) Partial losses (5-50 bbl/Hr) Severe losses (>50bbl/Hr) Complete losses (unable to maintain fluid level at surface with desired mud weight)

Hydrates Hydrates ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Hydrates What are hydrates? Hydrates are a solid mixture of water and natural gas (commonly methane). Once formed, hydrates are similar to dirty ice .

Hydrates Why are they important? Hydrates can cause severe problems by forming a plug in Well Control equipment, and may completely blocking flow path. One cubic foot of hydrate can contain as much as 170 cubic feet of gas. Hydrates could also form on the outside of the BOP stack in deepwater.

Hydrates Where do they form? In deepwater Drilling High Wellhead Pressure Low Wellhead temperature

Hydrates How to prevent hydrates? Good primary well control = no gas in well bore Composition of Drilling Fluid by using OBM or Chloride (Salt) in WBM. Well bore temperature as high as possible Select proper Mud Weight to minimize wellhead pressure. injecting methanol or glycol at a rate of 0.5 - 1 gal per minutes on the upstream side of a choke

Hydrates

Wet And Dry Tripping

Tripping Dry When a length of pipe is pulled from the hole, the mud level will fall.

The trip tank is then used to fill up the hole. Tripping Dry The volume of fall is equal to the volume of steel pulled from the hole. The trip tank is then used to fill up the hole. If 1 barrel of steel is removed from the hole, then using the trip tank, we have to add 1 barrel of mud.

1- Calculate the volume of steel pulled: Length x Metal Displacement Tripping Dry 1- Calculate the volume of steel pulled: Length x Metal Displacement Example: DP Metal Disp = 0.00764 bbls/ft Length Pulled 93 feet Volume Of Steel Pulled: 93 x 0.00764 = 0.711 bbls

Tripping Dry 2- Fill up the hole: You must pump 0.711 barrel of mud from the trip tank. You must investigate ( flow check) if more mud or less mud is needed.

It will drop inside the pipe and in the annulus. Tripping Dry 3- NO FILL UP: If you fail to fill up the hole, the mud level will drop by the volume of steel pulled. It will drop inside the pipe and in the annulus.

Tripping Dry 3- NO FILL UP: Example: DP Capacity: 0.01776 bbl/ft Volume Of Steel Pulled: 93 x 0.00764 = 0.711 bbls DP Capacity: 0.01776 bbl/ft Annular Capacity: 0.0504 bbl/ft The mud will drop inside the pipe and the annular: 0.01776 + 0.0504 = 0.06816 bbl/ft

Tripping Dry 3- NO FILL UP: Example Cont’d: The volume of drop is 0.711 bbls and will drop in a volume of 0.06816 bbl / ft, then the length of drop will be: 0.711 / 0.06816 = 10.4 feet. If 93 feet (1 stand) are pulled with no fill up, the mud level will drop by 10.4 feet.

Tripping Wet When a length of pipe is pulled from the hole, the mud level will fall.

The trip tank is then used to fill up the hole. Tripping Wet The volume of fall is equal to the volume of steel pulled from the hole plus the volume of mud inside this pipe. The trip tank is then used to fill up the hole. If 3 barrels of steel and mud are removed from the hole, then using the trip tank, we have to add 3 barrels of mud.

1- Calculate the volume of steel pulled: Length x Metal Displacement Tripping Wet 1- Calculate the volume of steel pulled: Length x Metal Displacement Example: DP Metal Disp = 0.00764 bbls/ft Length Pulled 93 feet Volume Of Steel Pulled: 93 x 0.00764 = 0.711 bbls

2- Calculate the volume of mud pulled: Tripping Wet 2- Calculate the volume of mud pulled: Length x DP Capacity Example: DP Capacity = 0.01776 bbls/ft Length Pulled 93 feet Volume Of Mud Pulled: 93 x 0.01776 = 1.65 bbls

3- Calculate the total volume of steel and mud pulled: Tripping Wet 3- Calculate the total volume of steel and mud pulled: 1.65 + 0.711 = 2.36 barrels

Tripping Wet 4- Fill up the hole: You must pump 2.36 barrels of mud from the trip tank. You must investigate ( flow check) if more mud or less mud is needed.

It will drop inside the annulus. Tripping Wet 5- NO FILL UP: If you fail to fill up the hole, the mud level will drop by the volume of steel and mud pulled. It will drop inside the annulus.

Tripping Wet 5- NO FILL UP: Example: Annular Capacity: 0.0504 bbl/ft Volume Of Steel and Mud Pulled: 93 x (0.00764+0.01776) = 2.36 bbls Annular Capacity: 0.0504 bbl/ft The mud will drop inside the annular by: 2.36 / 0.0504 = 46.9 feet

It is usefull to pump a slug before tripping. Pumping a Slug It is usefull to pump a slug before tripping. The slug weight being heavier than the mud, a length of pipe will be empty. The HP is not reduced because the heavier mud will compensate for the empty pipe.

The total HP is the same on both sides of the pipe. Pumping a Slug The total HP is the same on both sides of the pipe. HP kmw HP mud HP mud

Pumping a Slug Example: If 20 bbls of 12 ppg slug are pumped in a 10,000 ft hole containing 10 ppg mud, what will be the height of empty pipe? DP capacity = 0.01776 bbl/ft 1- Calculate the height of the slug: 20 / 0.01776 = 1126 ft

Pumping a Slug 2- Calculate the HP of the slug: 1126 x 12 x 0.052 = 702.6 psi 702.6 psi

Pumping a Slug 2- Calculate the HP of the mud in the annulus: 10,000 x 10 x 0.052 = 5,200 psi 702.6 psi 5,200 psi

Pumping a Slug 3- The total hydrostatic beeing the same on both sides, calculate the HP of the mud below the slug: 5,200 - 702.6 = 4497.4 psi 702.6 psi 5,200 psi 4497.4 psi

Pumping a Slug 4- Calculate the height of mud needed to give 4497.4 psi as a HP: TVD = 4497.4 / ( 10 x 0.052 ) = 8648.8 feet 1,126 ft 10,000 ft 8648.8 ft

Pumping a Slug 4- Calculate the height of empty pipe 10,000 - 8648.8 - 1,126 = 225.2 ft 225.2 ft 1,126 ft 10,000 ft 8648.8 ft