Bài giảng Well drilling engineering - Chapter 8: Kicks & Well control - Đỗ Quang Khánh

1 Well Drilling Engineering  Kicks & Well Control Dr. DO QUANG KHANH 2 Kicks and Well Control Methods The Anatomy of a KICK Kicks - Definition Kick Detection Kick Control (a) Dynamic Kick Control (b) Other Kick Control Methods * Driller’s Method * Engineer’s Method 3 Read:   Applied Drilling Engineering, Ch.4 HW#:  4 5 6 7 8 Causes of Kicks 9 Causes of Kicks 10 Causes of Kicks 11 What? What is a kick? An unscheduled entry of formation fluid(s) into the wellbore 12 Why? Why does a kick occur? The pressure inside the wellbore is lower than the formation pore pressure (in a permeable formation). p w < p f 13 How? How can this occur? Mud density is too low Fluid level is too low - trips or lost circ. Swabbing on trips Circulation stopped - ECD too low 14 What ? What happens if a kick is not controlled? BLOWOUT !!! 15 Typical Kick Sequence 1. Kick indication 2. Kick detection - (confirmation) 3. Kick containment - (stop kick influx) 4. Removal of kick from wellbore 5. Replace old mud with kill mud (heavier) 16 Kick Detection and Control Kick Detection Kick Control 17 1. Circulate Kick out of hole Keep the BHP constant throughout 18 2. Circulate Old Mud out of hole Keep the BHP constant throughout 19 Kick Detection Some of the preliminary events that may be associated with a well-control problem, not necessarily in the order of occurrence, are: 1. Pit gain; 2. Increase in flow of mud from the well 3. Drilling break (sudden increase in drilling rate) 20 Kick Detection 5. Shows of gas, oil, or salt water 6. Well flows after mud pump has been shut down 7. Increase in hook load 8. Incorrect fill-up on trips 4. Decrease in circulating pressure; 21 Dynamic Kick Control [Kill well “on the fly”] For use in controlling shallow gas kicks No competent casing seat No surface casing - only conductor Use diverter (not BOP’s) Do not shut well in! 22 Dynamic Kick Control 1. Keep pumping. Increase rate! (higher ECD) 2. Increase mud density 0.3 #/gal per circulation 3. Check for flow after each complete circulation 4. If still flowing, repeat 2-4. 23 Dynamic Kick Control Other ways that shallow gas kicks may be stopped: 1. The well may breach with the wellbore essentially collapsing. 2. The reservoir may deplete to the point where flow stops. 24 Conventional Kick Control {Surface Casing and BOP Stack are in place} Shut in well for pressure readings. (a) Remove kick fluid from wellbore; (b) Replace old mud with kill weight mud Use choke to keep BHP constant. 25 Conventional Kick Control 1. DRILLER’S METHOD ** TWO complete circulations ** Circulate kick out of hole using old mud Circulate old mud out of hole using kill weight mud 26 Conventional Kick Control 2. WAIT AND WEIGHT METHOD (Engineer’s Method) ** ONE complete circulation ** Circulate kick out of hole using kill weight mud 27 Driller’s Method - Constant Geometry Information required: Well Data: Depth = 10,000 ft. Hole size = 12.415 in. (constant) Drill Pipe = 4 1/2” O.D., 16.60 #/ft Surface Csg.: 4,000 ft. of 13 3/8” O.D. 68 #/ft (12.415 in I.D.) 28 Driller’s Method - Constant Geometry Kick Data: Original mud weight = 10.0 #/gal Shut-in annulus press. = 600 psi Shut-in drill pipe press. = 500 psi Kick size = 30 bbl (pit gain) Additional Information required: 29 Constant Annular Geometry. Initial conditions: Kick has just entered the wellbore Pressures have stabilized 30 Successful Well Control 1. At no time during the process of removing the kick fluid from the wellbore will the pressure exceed the pressure capability of the formation the casing the wellhead equipment 31 Successful Well Control 2. When the process is complete the wellbore is completely filled with a fluid of sufficient density (kill mud) to control the formation pressure. Under these conditions the well will not flow when the BOP’s are opened. 3. Keep the BHP constant throughout. 32 Calculations From the initial shut-in data we can calculate: Bottom hole pressure Casing seat pressure Height of kick Density of kick fluid 33 NOTE: The bottom hole pressure is kept constant while the kick fluid is circulated out of the hole! In this case BHP = 5,700 psig Circulate Kick Out of Hole 34 Constant Annular Geometry Driller’s Method. Conditions When Top of Kick Fluid Reaches the Surface BHP = const. 35 36 Top of Kick at Surface As the kick fluid moves up the annulus, it expands. If the expansion follows the gas law, then 37 Top of Kick at Surface Ignoring changes due to compressibility factor (Z) and temperature, we get: Since cross-sectional area = constant 38 Top of Kick at Surface We are now dealing two unknowns, P 0 and h 0 . We have one equation, and need a second one. BHP = Surface Pressure + Hydrostatic Head 5,700 = P o + D P KO + D P MA 5,700 = P o + 20 + 0.052 * 10 * (10,000 - h O ) 5,700 - 20 - 5,200 = P o - 0.52 * 39 Top of Kick at Surface 40 Well Control Worksheet Example: When circulating at a Kill Rate of 40 strokes per minute, the circulating pressure = 1,200 psi The capacity of the drillstring = 2,000 strokes Mud Weight = 13.5 lb/gal Well Depth = 14,000 ft 41 Aggie Drilling Research PRESSURE CONTROL WORKSHEET Division of PETE Dept., TAMU DATE: College Station, TX 77843-3116 TIME WELL CLOSED IN: 1. PRE-RECORDED INFORMATION System Pressure Loss @ 40 stks = 1,200 psi STROKES - Surface to Bit = 2,000 stks TIME - Surface to Bit - 2,000 stks / 40 stks/min = 50 min 2. MEASURE Shut-in Drill Pipe Pressure (SIDPP) = 800 psi Shut-in Casing Pressure (SICP) = 1,100 psi Pit Volume Increase (Kick Size) = 40 bbl 3. CALCULATE INITIAL CIRCULATING PRESSURE (ICP) ICP = System Pressure Loss + SIDPP = 1,200 + 800 = 2,000 psi 4. CALCULATE KILL MUD DENSITY (New MW) Mud Weight Increase = SIDPP / (0.052 * Depth) = 800/(0.052*14,000) = 1.10 lb/gal Kill Mud Density (New MW) = Old MW + MW Increase = 13.5 + 1.10 = 14.6 lb/gal 5. CALCULATE FINAL CIRCULATING PRESSURE (FCP) FCP = System Pressure Loss * (New MW / Old MW) = 1,200 * (14.6 / 13.5) = 1,298 psi 42 1,298 0 Graphical Analysis Final Circ. Press., FCP, psi Initial Circ. Press., ICP, psi 3,000 2,000 1,000 0 3,000 2,000 1,000 43 Csg DS DS Csg Pressure When Circulating Static Pressure First Circulation Second Circulation DrillPipe Pressure Driller’s Method 1,298 2,000 800 2,000 stks 44 Csg DS DS Csg Casing Pressure Volume Pumped, Strokes Drillpipe Pressure Driller’s Method 800 1,100 0 psi 800 DP Press. 0 psi 45 1 6 5 4 3 2 Engineer’s Method