Unconventional Kill Methods 0 Unconventional Kill Methods 1 / 35 Which of the following statements best describe the Volumetric Method? Maintains constant bottom hole pressure as the gas kick migrates to the surface Maintains constant bottom hole pressure as the water kick migrates to the surface Maintains the pressure insite the kick constant as the kick is migrating to the surface Maintains the hydrostatic pressure in the annulus constant as the kick is migrating to the surface 2 / 35 A gas kick is swabbed-in while pulling out of the hole and, after stabilization, the kick is migrating. Once circulation is not possible at the moment, what well control method can be used to offset the gas migration? Driller's Method Wait and Weight Method Volumetric Method Lubricate and Bleed 3 / 35 Use the information below to answer the following questions: Shut-In Tubing Pressure = 2,175 psi Shut-In Casing Pressure = 0 psi Desired Overbalance = 200 psi Formation Pressure Gradient = 0.5980 psi/ft Fracture Pressure Gradient = 0.7176 psi/ft Top of Perfs = 5017 ft TVD/MD Bottom of Perfs = 5059 ft TVD/MD What is the bottom hole pressure (BHP) and Formation Pressure? BHP = FP = 3000 psi BHP = 3200 psi and FP = 3000 psi FP = 3200 psi and BHP = 3000 psi BHP = 200 psi and FP = 3000 psi 4 / 35 Use the information below to answer the following questions: Shut-In Tubing Pressure = 2,175 psi Shut-In Casing Pressure = 0 psi Desired Overbalance = 200 psi Formation Pressure Gradient = 0.5980 psi/ft Fracture Pressure Gradient = 0.7176 psi/ft Top of Perfs = 5017 ft TVD/MD Bottom of Perfs = 5059 ft TVD/MD What is the Kill Fluid Density with a 200 psi Overbalance Pressure (OB)? 12.2 ppg 12.3 ppg 13 ppg 12 ppg 5 / 35 Use the information below to answer the following questions: Shut-In Tubing Pressure = 2,175 psi Shut-In Casing Pressure = 0 psi Desired Overbalance = 200 psi Formation Pressure Gradient = 0.5980 psi/ft Fracture Pressure Gradient = 0.7176 psi/ft Top of Perfs = 5017 ft TVD/MD Bottom of Perfs = 5059 ft TVD/MD What is the Maximum Tubing Pressure Initial (MTPI)? 2775 psi 3200 psi 3000 psi 2175 psi 6 / 35 Use the information below to answer the following questions: Shut-In Tubing Pressure = 2,175 psi Shut-In Casing Pressure = 0 psi Desired Overbalance = 200 psi Formation Pressure Gradient = 0.5980 psi/ft Fracture Pressure Gradient = 0.7176 psi/ft Top of Perfs = 5017 ft TVD/MD Bottom of Perfs = 5059 ft TVD/MD What is the Maximum Tubing Pressure Initial (MTPI)? 3200 psi 280 psi 391 psi 3600 psi 7 / 35 What is is the controlling pressure in the Bullheading Method? Tubing Pressure Casing Pressure Formation Pressure Casing Burst Pressure 8 / 35 What is is the controlling pressure in the Reverse Circulation Method? Tubing Pressure Casing Pressure Formation Pressure Casing Burst Pressure 9 / 35 Which method results in higher Equivalend Circulation Density (ECD)? Reverse Circulation Lubricate and Bleed Bullheading Volumetric Method 10 / 35 In Bullheading operations, as the kill fluid is being pumped down the tubing and the perforations are accepting fluids, the tubing pressure should be: Increase Stay the same There is no way to know Decrease 11 / 35 Reverse circulation must be conducted with care in order to avoid: Dislodging the packer Rupturing the casing All of the above Collapsing the tubing 12 / 35 The minimum volume required to bullhead successfully includes the surface lines, tubing volume and: The volume below the packer to the end of the tubing The volume from the end of the tubing to the bottom of the perforations The volume required to over-displace and force the kill fluid into the formation The volume to pump a bottoms-up through the casing 13 / 35 Reverse circulation can be complicated by high ECD’s. If pumping past the packer, these high ECD’s can increase Bottom Hole Pressure. What causes the high ECD’s? The low viscosity of the completion fluid The high friction values when circulating fluid down the annulus Increase in formation pressure from a producing well The high friction values when circulating fluid up the tubing string 14 / 35 What factor can have an effect on the rate of gas migration? The angle of the well bore The rheology (viscosity and density) of the fluid in the well The type of fluid in the well All of the above can have an effect on migration rates 15 / 35 When Bullheading, the Bottom Hole Pressure will remain fairly constant throughout the operation. This statement is true This statement is false There is no way to know It depends on the Formation Pressure 16 / 35 Use the well information below to answer the following question: Brine Density: 10.5 ppg Top of Perfs: 9525 MD/TVD Tubing Friction @ 30 SPM: 800 psi Casing Friction @ 30 SPM 65 psi When circulating conventionally, the pump pressure is 865 psi. What is the Bottom Hole Pressure (BHP)? 5266 psi 6001 psi 5136 psi 4336 psi 17 / 35 Use the well information below to answer the following question: Brine Density: 10.5 ppg Top of Perfs: 9525 MD/TVD Tubing Friction @ 30 SPM: 800 psi Casing Friction @ 30 SPM 65 psi When reverse circulating, the pump pressure is 865 psi. What is the Bottom Hole Pressure (BHP)? 5266 psi 6001 psi 5136 psi 4336 psi 18 / 35 Use the information below to answer the following question. Average Fluid Density in Tubing = 7.43 ppg Calculated KWM required: 9.9 ppg Top Perforations = 8500 feet TVD Bottom Perforations = 8750 feet TVD Fracture Gradient = 0.62 psi/foot What is the Bullheading Maximum Tubing Pressure Final (MTPF) when Kill Weight Fluid reaches the top perforations? 4376 psi 5270 psi 894 psi 1926 psi 19 / 35 Use the information below to answer the following question. SITP = 2300 psi TVD = 7200 feet Fluid Density in Tubing = 3.5 ppg Average Wellbore Temperature (AWBT) = 185 °F Surface Mixing Temperature = 75 °F Please use the following density temperature chart. What brine weight (with no safety factor) should be mixed on surface to bullhead the well given the following information? 10.0 ppg 9.7 ppg 10.5 ppg 10.4 ppg 20 / 35 Use the information below to answer the following question. Top Perforations = 9000 feet TVD Bottom Perforations = 9250 feet TVD Pore Pressure Gradient = .525 psi/feet SITP = 1100 psi SICP = 0 psi What is the kill weight fluid (no safety margin) required to kill the well by Bullheading? 9.9 ppg 10.7 ppg 10.8 ppg 10.1 ppg 21 / 35 Which of the following is one of the main advantages of a reverse circulation kill? It is slow Wireline work is involved Debris can plug the formation The tubing and annulus end up with clean kill fluid 22 / 35 A well (10525 ft MD / 10400 ft TVD) is to be killed with 9.5 ppg brine. The formation pressure is 4950 psi. Which statement is true? There will be a 250 psi overbalance at the formation There will be a 188 psi overbalance at the formation The formation will be balanced There will be a 188 psi underbalance at the formation 23 / 35 In which of the following situations is Bullheading most likely to be used to kill the well? A well with a overbalance greater than 150 psi Where there is not enough information to calculate a reverse circulation kill Where there is a risk of formation damage A well with a packer setting plug stuck in the tailpipe 24 / 35 Which of the following statements about Bullheading is true? Can only be done if the perforations are open. Can be done before the intervention work starts when there is a two way check valve in the tubing hanger. Is normally done in preference to opening the SSD. Is more difficult to perform than the bleed and lubricate method. 25 / 35 Which of the following statements about Bullheading is true? Can be done before the intervention work starts when there is a two way check valve in the tubing hanger. Can possibly plug the formation. Is normally done in preference to opening the SSD. Is more difficult to perform than the bleed and lubricate method. 26 / 35 Which of the following best describes the Lubricate & Blled Method? Is performed by bleeding off the wellhead pressure to zero and circulating the tubing to kill fluid Is performed by bleeding off the wellhead pressure to zero and topping up the tubing with kill fluid Is performed by pumping a tubing volume of kill fluid and then bleeding off the wellhead pressure to zero Is performed by repeatedly pumping a small amount of kill fluid then bleeding off a small amount of pressure 27 / 35 Use the information below to answer the following question. You have just started up the pump at 3 bbls/min and have 875 psi pump pressure. Brine weight – 10.2 ppg Well depth – 8,000 feet Calculated inside tubing pressure loss – 800 psi Calculated annular pressure loss – 75 psi Calculate the current bottom hole pressure (BHP) with conventional circulation. 4243 psi 4318 psi 5043 psi 5918 psi 28 / 35 Use the information below to answer the following question. You have just started up the pump at 3 bbls/min and have 875 psi pump pressure. Brine weight – 10.2 ppg Well depth – 8,000 feet Calculated inside tubing pressure loss – 800 psi Calculated annular pressure loss – 75 psi Calculate the current bottom hole pressure (BHP) with reverse circulation. 4243 psi 4318 psi 5043 psi 5918 psi 29 / 35 A formation pressure is 6922 psi at 10321 ft. If the well has a shut-in tubing pressure of 2250 psi, what is the average density in ppg of the fluid in the tubing? 9.2 ppg 8.7 ppg 5.2 ppg 9.6 ppg 30 / 35 Bullheading requires annular velocity in the tubing to exceed the gas migration rate. Calculate the minimum required pump speed (SPM) to successfully bullhead down the tubing in this well. Tubing capacity: 2 3/8”, 4.7 lbs/foot, N80, 0.00378 bbls/foot Migration rate of gas: 3400 feet/hour Pump output: 0.0480 bbl/stk 9 SPM 7 SPM 5 SPM 3 SPM 31 / 35 Bullheading requires annular velocity in the tubing to exceed the gas migration rate. Calculate the minimum required pump speed (SPM) to successfully bullhead down the tubing in this well. Tubing capacity: 2 3/8”, 4.7 lbs/foot, N80, 0.00378 bbls/foot Migration rate of gas: 2200 feet/hour Pump output: 0.0480 bbl/stk 9 SPM 7 SPM 5 SPM 3 SPM 32 / 35 The Volumetric Method is being use to allow gas bubble expansion as the bubble migrates to the surface. When gas reached the surface the well must be shut in and a circulating method of well control performed. Choose the most applicable method for killing a well without tubing. Pump mud and bleed gas in calculated steps Bleed gas and pump mud in calculated steps Bleed gas from the choke and open the well Open the well since the gas pressure is almost zero 33 / 35 Based on static conditions before beginning to pump, calculate the Maximum Initial surface pressure limit for a Bullheading operation. SITP = 2400 psi SICP = 0 psi Top Perforation = 9400 feet MD / TVD Bottom Perforation = 9600 feet MD /TVD Formation Fracture = 5339 psi Formation Pressure = 3234 psi 2940 psi 4506 psi 2106 psi 5501 psi 34 / 35 During Bullheading operations the Kill Weight Fluid is calculated using TVD of the Top Perforations and Volume to Pump is calculated using Lower Perforations MD. This statement is True This statement is False There are no calculations involved with the Bullheading Method There is no way to know 35 / 35 What are the main calculations required before beginning bullheading operations? Total tubing volume, kill fluid, maximum pressures Total tubing volume, maximum pressures Total volume from the surface to lower perforations; kill fluid weight in ppg, and maximum pressures. Kill fluid, maximum pressures Your score is LinkedIn Facebook Twitter VKontakte
