What is Important for the Final Exam PDF

What is Important for the Final Exam? Bit Types: Roller-Cone / Rock Bits Two Types: Milled Tooth or Tungsten Carbide Insert (TCI) Milled tooth: cutting structure milled from steel TCI: cutting structure made of hard inserts pressed into cone Dri...

What is Important for the Final Exam? Bit Types: Roller-Cone / Rock Bits Two Types: Milled Tooth or Tungsten Carbide Insert (TCI) Milled tooth: cutting structure milled from steel TCI: cutting structure made of hard inserts pressed into cone Drilling Action Suitable for large variety of formation types and applications Cutting action when string is rotated and teeth/insert roll and skid along bottom of hole, causing rock crushing and scraping/ploughing Shape of teeth affect drilling action: larger teeth = more aggressive cutting structures for softer formations Formation Insert / Tooth Insert / Tooth ROP & Cuttings Cleaning Flow Strength Spacing Properties Generation Rate Soft Wide Long & Sharp High High Medium Relatively Wide Shorter & Stubbier Relatively High Relatively High Hard Close Short & Rounded Relatively Low Relatively Low 2 © Dr. Eric van Oort Roller Cones for Soft & Hard Formations 3 © Dr. Eric van Oort Bit types: Fixed Cutter/Drag Bit - PDC PDC’s have no moving parts, no roller bearings (main advantage over roller-cones) Rock failure by shear rather than crushing (less energy) Two Body Types: Steel-PDC bits machined from wrought, high-performance alloy steel; are structurally stronger and tougher than matrix bits; are relatively easy to manufacture and can be delivered relatively quickly; dimensionally more accurate and more repeatable than cast bits; can be easily refurbished; must be protected, however against abrasion and erosion with hardfacing Matrix bits are cast from matrix material (Tungsten Carbide grains with metallic binder); are far more abrasion and erosion resistant than steel-bodied bits, preferred in cases where the body is likely to be the cause of bit failure (e.g in smaller diameter hole); require support from an internal, steel structure member (a “blank”) Cutters have Tungsten Carbide substrate & Diamond table 4 © Dr. Eric van Oort Bit types: Fixed Cutter Bit – Impreg & Diamond Bits Matrix PDC body (made form e.g. Tungsten Carbide) Matrix impregnated with diamonds, imbedded to prevent breakage Diamonds are small -> depth of cut is small -> run at high RPM using turbodrills or high-speed PDMs Sensitive to shocks & vibrations 5 © Dr. Eric van Oort Bit Selection Formation Unconfined Suitable Suitable Suitable Suitable for Description Compressive Strength for Milled for TCI ? for PDC? Diamond Tooth? Impreg? Very Soft < 4,000 psi Yes No* Yes No Soft 4,000 – 9,000 psi Yes No* Yes No Medium 9,000 – 15,000 psi No Yes Yes No Hard 15,000 – 22,000 psi No Yes Yes Yes Very Hard > 22,000 psi No Yes Yes! Yes * Application of TCI is possible but would not be economically preferred Selection Methodology Consider formation hardness and eliminate unsuitable bit types Consider bit economics using ROP, time savings, rig costs and bit prices (next slide) Consider the requirements of special factors such as directional requirements Note that the operating envelope for PDC’s continues to expand 6 © Dr. Eric van Oort  The Drill String - DS Transmits rotary power (torque) to the bit Provides weight-on-bit (WOB) Controls well trajectory (deviation & azimuth) Transports drilling fluid to the bit Enables monitoring / logging while drilling (MWD/LWD) Currently done through mud pulse telemetry In near-future, done with wired / intelligent drillpipe Mud-Pulse Telemetry Wired “Intelligent” Drillpipe 7 © Dr. Eric van Oort  What Moves the DS & Bit? Surface: Kelly and Rotary Table: Rotary Table rotates the Kelly Master Bushing, which rotates the Kelly Bushing, which rotates the Kelly Kelly rotates the entire drill string and thus the bit Surface: Top Drive: Top Drive rotates the Drill String and thus the bit Rotary Table still available but generally not used (only when TD is offline) Downhole: Mud Motor / Turbine “Sliding” Drilling Fluid pumped from the mud pumps to the swivel to Drill String Drilling Fluid ‘forced’ through Mud Motor above bit Mud Motor Stator and Drill String remain stationary, but rotor & bit rotate in preferred direction Surface & Downhole: Rotary Steerable System (RSS) Top Drive rotates the Drill String RSS steers the orientation of the bit through push-the-bit or point-the- bit technology 8 © Dr. Eric van Oort Drill String Components Overview Not shown: BHA components such as downhole motors, MWD/LWD equipment etc. 9 © Dr. Eric van Oort  A Very Simple Drillstring 10 © Dr. Eric van Oort  Drillpipe Characteristics Length Range 1: 18-22 ft (now Allowable DP body obsolete) Singles, Doubles & elongation range is Range 2: 27-30 ft Triples (Stands) 0.5% for grade E, 0.6% Range 3: 38-45 ft for grades X & G, 0.7% for grade S Size & Weight Common: 3 ½”, 4 ½”, 5” Uncommon: 2 3/8”, 2 7/8”, API Grade API Yield Strength Tensile Strength 4”, 5 ½”, 5 7/8”, 6 5/8” Min (ksi) Max (ksi) Minimum (ksi) Larger DP for large diameter hole, lower E-75 75 105 100 frictional pressure loss, high X-95 95 125 105 torsional strength (ERD & DW) G-105 105 135 115 S-135 135 165 145 Grade & API Z-140 140 160 150 Classification V-150 150 180 160 11 © Dr. Eric van Oort  Drill Collars Drill collars are large diameter, thick tubes that are very heavy. They are connected using a similar thread to the drill pipe. These heavy tubes are used to provide weight at the bottom of the well. Therefore, they are run in compression and are asked to survive a severe load. In order to make sure the drill pipe is not in compression it is common to not use more than 80% of the buoyed drill collar weight. 12 © Dr. Eric van Oort Drill Collar Characteristics OD: 4 ¾”, 6”, 8”, 9 ½” ID: 2”, 2 ½”, 2 3/8”, 3” Length: Typically Range 2 Material: (stainless) steel, monel (non-magnetic drill collars- NMDC) Connection: 6 5/8” REG, NC-50, etc. cut (not welded) at both ends Spiral (reduced contact area), square, etc. 13 © Dr. Eric van Oort  Drill Collar Sizes Drill Collar size affected by following factors: Bit size OD of casing (coupling) to be run in hole Formation dip & heterogeneity Hydraulics program Directional program (max. DLS) Required WOB Possibility of fishing operations 14 © Dr. Eric van Oort Heavy Wall Drill Pipe (HWDP) Heavy Wall Drill Pipe (“Hevi-Wate”) is intermediate weight between drill collars and regular drill pipe Heavy-wall tubes with upset in middle (central wear pad) and long tool joints Serves to make DC DP crossover more gradual. HWDP more resilient to fatigue, compression Used in slim-hole and high deviation applications, instead of DC’s (lower contact area, less differential sticking risk) Less torque, higher tripping speeds, no loss of BOP control (pipe rams same as regular DP) Weight ID (in) Wall Thickness Tooljoint Tooljoint (lbs/ft) (in) ID (in) OD (in) 5” DP 22.79 4.276 0.362 3 1/4 6 5/8 5” HWDP 52.34 3 1.0 3 1/16 6 5/8 15 © Dr. Eric van Oort Stabilizers Centralization Help keep string more central in hole, depending on distance between stabilizers, size, hole size and number Directional Effect Act as fulcrum in directional drilling, highly dependent on position BHA Prevention of Buckling Torque & Drag Profound increase in torque, limiting maximum number of stabs typically to 4 Rock Cutting Effect (secondary) Vibration Effect +/- Stuck Pipe Effect +/- 16 © Dr. Eric van Oort Miscellaneous String Components Subs Crossover subs/collars (box/box, pin/pin, pin/box) Float subs Dart subs Circulating Subs Bent subs / orienting sub Shock subs Jars & Accelerators Bumper subs Jars (drilling & fishing) Accelerators MWD / LWD Tools (GR, RES, neutron density/porosity, sonic, formation pressures, etc.) 17 © Dr. Eric van Oort Turbines & Downhole Motors Motor Turbine 18 © Dr. Eric van Oort Land Drilling - Vertical Drillstring 12 1/4" BHA -- Packed Assembly Number OD Average Component Acronyms: of Joints (in) Length (ft) HWDP = heavy wall drillpipe Drill Pipe To Surface 5 as applicable DC = drill collar HWDP 14 5 434 IBS = integral blade stabilizer Crossover 1 6.5 3 NBS = near bit stabilizer DC 9 6.5 275 Crossover 1 8 2 DC 3 8 90 IBS 1 8.25 5 DC 1 8 31 IBS 1 8.25 5 Pony Collar 1 8 10 NBS 1 8.25 5 Bit 1 12.25 1 Pony = Short Horse Pony Collar = Short Drill Collar 19 © Dr. Eric van Oort Actual Deepwater Drillstring WATER DEPTH + RKB 7,875 DEPTH IN 17,800 DEPTH OUT 21,500 TOTAL 3,700 OBJECTIVE: Drill ahead 12 1/4" hole to the planned 9 3/8" casing point. Hole must be maintained at or near vertical. MW = 12 0.81663 ITEM GAUGE BODY BODY DOWN UP UNIT ACCUM. AIR CUM AIR BUOYED NO. DESCRIPTION VENDOR OD OD ID CONN CONN LENGTH LENGTH WT/FT WT WT WEIGHT 1 12 1/4" BIT 12.25 6 5/8 R P 2.0 2.0 200 400 400 327 2 9 1/2" T1H Turbine STC 12.13 12.75 3.00 6 5/8 R B 7 5/8 R B 45.0 47.0 210 9450 9850 8044 3 IB STRING STABILIZER BHI 12.13 9.50 3.00 7 5/8 R P 7 5/8 R B 7.0 54.0 210 1470 11320 9244 4 MWD (Dir/Res/Gam/PWD/TC) W/Scre BHI 9.50 3.00 7 5/8 R P 7 5/8 R B 60.0 114.0 210 12600 23920 19534 5 IB STRING STABILIZER BHI 12.13 9.50 3.00 7 5/8 R P 7 5/8 R B 7.0 121.0 210 1470 25390 20734 6 X-OVER SUB (BOTTLENECK) RIG 9.50 3.00 7 5/8 R P 6 5/8 R B 4.0 125.0 210 840 26230 21420 7 PBL SUB DHD 8.25 2.81 6 5/8 R P 6 5/8 R B 8.0 133.0 180 1440 27670 22596 8 (3) 8 1/4" DRILL COLLARS BHI 8.25 2.81 6 5/8 R P 6 5/8 R B 90.0 223.0 180 16200 43870 35825 9 WBRRT RIG 12.25 8.00 3.00 6 5/8 R P 6 5/8 R B 7.0 230.0 180 1260 45130 36854 10 X-OVER SUB RIG 8.25 2.81 6 5/8 R P 6 5/8 FH B 3.0 233.0 150 450 45580 37222 11 (9) 6 5/8" HWDP RIG 6.63 4.50 6 5/8 FH P 6 5/8 FH B 270.0 503.0 75 20158 65738 53684 12 DRILLING JAR 7.00 2.88 6 5/8 FH P 6 5/8 FH B 30.0 533.0 150 4500 70238 57358 13 (8) 6 5/8" HWDP RIG 6.63 4.50 6 5/8 FH P 6 5/8 FH B 240.0 773.0 75 17918 88157 71991 14 6 5/8" S-135 DP (27.7# ) RIG 6.63 5.90 6 5/8 FH P 6 5/8 FH B 10000.0 10773.0 33 334700 422857 345316 15 6 5/8" S-135 DP (34# ) RIG 6.63 5.58 6 5/8 FH P 6 5/8 FH B 10727.0 21500.0 43 461261 884118 721993 0 422857 345316 WEIGHTS AND LENGTHS ARE APPROXIMATION ONLY MWD = Monitoring While Drilling FLOAT INSTALLED IN MOTOR X-Over = Cross-Over PBL = Bypass Circulation Sub FLOW RATES: 700 - 800 GPM BHA AIR WEIGHT (Lbs): 88,157 WBRRT = Wear Bushing Running / Retrieving Tool MUD WEIGHTS: 11.6 - 13.3 PPG BHA WT IN MUD (Lbs): 71,991 HWDP = Heavy Weight Drillpipe MUD TYPE: SEAWATER (w/gel sweeps) BELOW JARS (Lbs): 57,358 WOB: As Required 20 © Dr. Eric van Oort  Drill String Design Overview – Axial & Torsional Loads Only Dry Weight Buoyant Weight Weight-on-Bit (WOB) & Neutral Point (NP) Com- Tension Buckling pression Vertical Hole NP Deviated Hole Loads on drill string Tension Loads Bending Stresses Combined Tension & Torsional Loads 21 © Dr. Eric van Oort Axial Tension: Weight in Air / Dry Weight Which string (A,B,C or D) produces the highest tension at surface? 𝑂𝑂𝑂𝑂2 − 𝐼𝐼𝑂𝑂2 𝑊𝑊𝑎𝑎𝑎𝑎𝑎𝑎 = 𝜋𝜋 × 𝜌𝜌 × 4 Total Depth (TD) 22 © Dr. Eric van Oort  Buoyancy & Archimedes A body immersed in a fluid experiences a buoyant force equal to the weight of the fluid it displaces The buoyant force will reduce the effective weight of the body accordingly 𝜌𝜌𝑚𝑚𝑚𝑚𝑚𝑚 𝑊𝑊𝑏𝑏 = 𝐾𝐾𝑏𝑏 × 𝑊𝑊𝑎𝑎𝑎𝑎𝑎𝑎 , 𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤 𝐾𝐾𝑏𝑏 = 1 − 𝜌𝜌𝐷𝐷𝐷𝐷 𝑐𝑐𝑐𝑐𝑚𝑚𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝜌𝜌𝑚𝑚𝑚𝑚𝑚𝑚 (𝑝𝑝𝑝𝑝𝑝𝑝) 𝑓𝑓𝑓𝑓𝑤𝑤 𝑠𝑠𝑠𝑠𝑤𝑤𝑤𝑤𝑠𝑠: 𝐾𝐾𝑏𝑏 = 1 − 65.5 23 © Dr. Eric van Oort  Weight-on-Bit (WOB) and Neutral Point (NP) Hookload Compression Tension 0 Weight slacked- off on surface Effective DS weight after slack-off DS weight fully supported by Neutral hookload Point (NP) ~ 90% of BHA weight generated by DC’s (& HWDP) Weight-on-Bit (WOB) 24 © Dr. Eric van Oort  Drill Collar Equations Weight (lb/ft) 𝑊𝑊𝐷𝐷𝐷𝐷 = 𝜋𝜋 × 𝜌𝜌 × 𝑂𝑂𝑂𝑂2 − 𝐼𝐼𝑂𝑂2 = 2.67 × 𝑂𝑂𝑂𝑂2 − 𝐼𝐼𝑂𝑂2 4 Recommended Collar 𝑂𝑂𝑂𝑂 = 2𝑂𝑂𝑂𝑂𝐷𝐷𝐷𝐷𝐷𝐷 − 𝑂𝑂𝐵𝐵𝑎𝑎𝑐𝑐 Size (in) Diameter of the casing collar that is going to be run in the hole Required Length 𝑂𝑂𝐷𝐷 × 𝑊𝑊𝑂𝑂𝑊𝑊 𝐿𝐿𝐷𝐷𝐷𝐷 = (ft) for WOB 𝑊𝑊𝐷𝐷𝐷𝐷 × 𝐾𝐾𝑏𝑏 × cos 𝜑𝜑 DF is a design / safety factor that is included to guarantee that the NP is located in BHA 25 © Dr. Eric van Oort Example Simple Drill Collar Calculation * Problem by Mitchell & Miska, 2011, Ch.9 𝑂𝑂𝐷𝐷 × 𝑊𝑊𝑂𝑂𝑊𝑊 𝐿𝐿𝐷𝐷𝐷𝐷 = 𝑊𝑊𝐷𝐷𝐷𝐷 × 𝐾𝐾𝑏𝑏 × cos 𝜑𝜑 𝑂𝑂𝑂𝑂2 − 𝐼𝐼𝑂𝑂2 𝑊𝑊𝑚𝑚𝑐𝑐 𝑠𝑠𝑙𝑙/𝑓𝑓𝑠𝑠 = 𝜋𝜋 × 𝜌𝜌 × = 2.67 × 𝑂𝑂𝑂𝑂2 − 𝐼𝐼𝑂𝑂2 4 One joint of DC -> 30 ft (Range 2 pipe) 635 / 30 -> 22 joints minimum required Design Factor included to keep neutral point within the BHA and avoid buckling DP 26 © Dr. Eric van Oort  Buckling – Vertical Hole Lubinski (1957, 1981): First Order Buckling: 𝑊𝑊𝐷𝐷𝐶𝐶,𝐼𝐼 = 1.94 × 𝑊𝑊𝑏𝑏 × 𝑚𝑚 First buckle contacts wellbore wall Second Order Buckling: 𝑊𝑊𝐷𝐷𝐶𝐶,𝐼𝐼𝐼𝐼 = 3.75 × 𝑊𝑊𝑏𝑏 × 𝑚𝑚 Second buckle contacts wellbore wall 3 𝐸𝐸𝐼𝐼 𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤: 𝑚𝑚 = 𝑊𝑊𝑏𝑏 𝑎𝑎𝑎𝑎𝑎𝑎 𝐸𝐸 = 𝑌𝑌𝑓𝑓𝑌𝑌𝑎𝑎𝑝𝑝′ 𝑠𝑠 𝑀𝑀𝑓𝑓𝑎𝑎𝑌𝑌𝑠𝑠𝑌𝑌𝑠𝑠 𝜋𝜋 𝐼𝐼 = 𝑚𝑚𝑓𝑓𝑚𝑚𝑤𝑤𝑎𝑎𝑠𝑠 𝑓𝑓𝑓𝑓 𝐼𝐼𝑎𝑎𝑤𝑤𝑤𝑤𝑠𝑠𝐼𝐼𝑎𝑎 = 𝑂𝑂𝑂𝑂4 − 𝐼𝐼𝑂𝑂4 64 27 © Dr. Eric van Oort  Buckling – Deviated Hole Dawson & Paslay (1983): Sinusoidal or Snaking Buckling: 𝑊𝑊𝑏𝑏 × 𝐸𝐸 × 𝐼𝐼 × sin 𝜑𝜑 𝑊𝑊𝐷𝐷𝐶𝐶 = 2 𝑤𝑤𝑐𝑐 𝑤𝑤𝑐𝑐 = 0.5 × 𝑂𝑂𝑏𝑏𝑎𝑎𝑐𝑐 − 𝑂𝑂𝑂𝑂𝐷𝐷𝐷𝐷 Where: E = Young’s Modulus [lbf/ft2] I = Moment of Inertia [ft-4] Wb = buoyed weight [lbm/ft] rc = characteristic radius [ft] φ = hole angle [degrees or rad] 28 © Dr. Eric van Oort  Buckling – Deviated Hole Calculation * Problem by Mitchell & Miska, 2011, Ch.9 𝑊𝑊𝑏𝑏 × 𝐸𝐸 × 𝐼𝐼 × sin 𝜑𝜑 𝑊𝑊𝐷𝐷𝐶𝐶 = 2 𝑤𝑤𝑐𝑐 Conclusion: buckling in deviated hole will usually require much higher WOB than in vertical hole, usually outside of the recommended range for effective drilling 29 © Dr. Eric van Oort  Convex Uniaxial Tension: Bending Concave 30 © Dr. Eric van Oort  Bending Stresses In drilling ops, the DS frequently undergoes bending because of hole curvature (doglegs) Bending adds to the axial tensile loading of the DS 𝑀𝑀𝑏𝑏 𝑂𝑂𝑐𝑐 𝑊𝑊𝑤𝑤𝑎𝑎𝑎𝑎𝐼𝐼𝑎𝑎𝑝𝑝 𝑆𝑆𝑠𝑠𝑤𝑤𝑤𝑤𝑠𝑠𝑠𝑠 = 𝜎𝜎𝑏𝑏 = 2𝐼𝐼 𝐸𝐸 × 𝑂𝑂𝐿𝐿𝑆𝑆 × 𝑂𝑂𝑐𝑐 𝑊𝑊𝑤𝑤𝑎𝑎𝑎𝑎𝐼𝐼𝑎𝑎𝑝𝑝 𝑀𝑀𝑓𝑓𝑚𝑚𝑤𝑤𝑎𝑎𝑠𝑠 = 𝑀𝑀𝑏𝑏 = 𝐸𝐸𝐼𝐼𝜅𝜅𝑏𝑏 𝜎𝜎𝑏𝑏 = 2 × 5,729.6 × 12 1 𝐶𝐶𝑌𝑌𝑤𝑤𝐶𝐶𝑎𝑎𝑠𝑠𝑌𝑌𝑤𝑤𝑤𝑤 = 𝜅𝜅𝑏𝑏 = 𝐸𝐸 ≅ 30 × 106 𝑝𝑝𝑠𝑠𝐼𝐼 𝑅𝑅 360 × 100 5,729.6 𝑅𝑅𝑎𝑎𝑎𝑎𝐼𝐼𝑌𝑌𝑠𝑠 𝑓𝑓𝑓𝑓 𝐶𝐶𝑌𝑌𝑤𝑤𝐶𝐶𝑎𝑎𝑠𝑠𝑌𝑌𝑤𝑤𝑤𝑤 = 𝑅𝑅 = = 2𝜋𝜋 × 𝑂𝑂𝐿𝐿𝑆𝑆 𝑂𝑂𝐿𝐿𝑆𝑆 𝜎𝜎𝑏𝑏 ≅ 218 × 𝑂𝑂𝐿𝐿𝑆𝑆 × 𝑂𝑂𝑐𝑐 𝑂𝑂𝑓𝑓𝑝𝑝 𝐿𝐿𝑤𝑤𝑝𝑝 𝑆𝑆𝑤𝑤𝐶𝐶𝑤𝑤𝑤𝑤𝐼𝐼𝑠𝑠𝑆𝑆 = 𝑂𝑂𝐿𝐿𝑆𝑆 𝐼𝐼𝑎𝑎 𝑎𝑎𝑤𝑤𝑝𝑝𝑤𝑤𝑤𝑤𝑤𝑤𝑠𝑠/100𝑓𝑓𝑠𝑠 31 © Dr. Eric van Oort Handling Combined Loads with VME Stress 1 2 2 2 𝜎𝜎𝑉𝑉𝑉𝑉𝑉𝑉 = 𝜎𝜎𝑎𝑎 − 𝜎𝜎𝜗𝜗 + 𝜎𝜎𝜗𝜗 − 𝜎𝜎𝑎𝑎 + 𝜎𝜎𝑎𝑎 − 𝜎𝜎𝑎𝑎 + 6𝜏𝜏 2 2 σa = Total axial stress includes buoyant Torsional Stress axial stress and bending stress Ignoring tangential (σθ) and radial (σr) stresses, Von Mises Equivalent stress reduces to: 2 𝜎𝜎𝑉𝑉𝑉𝑉𝑉𝑉 = 𝜎𝜎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎 + 𝜎𝜎𝑏𝑏𝑐𝑐𝑐𝑐𝑚𝑚𝑎𝑎𝑐𝑐𝑏𝑏 + 3𝜏𝜏 2 To check the load-bearing capacity, the Von Mises Equivalent stress should be compared with the API yield strength Sy of the pipe: 𝜎𝜎𝑉𝑉𝑉𝑉𝑉𝑉 ≤ 𝑆𝑆𝑌𝑌 32 © Dr. Eric van Oort  DS Design for Vertical Well Based on Tensile Pull Load Case 33 © Dr. Eric van Oort  Calculations for a Deviated Well including Bending Angle Build Up Section Angle Drop Off Section 34 © Dr. Eric van Oort  Calculations for Combined Loads 35 © Dr. Eric van Oort  Drill Pipe Parameters DP spec’s summarized in API RP 7G 36 © Dr. Eric van Oort  Example 1 & Solution * Problem by Mitchell & Miska, 2011, Ch.9 Lbf 37 © Dr. Eric van Oort (75,000 x 4.3037 = 322,777 lbf without torsion)  Example 2 & Solution * Problem by Mitchell & Miska, 2011, Ch.9 𝐸𝐸 × 𝑂𝑂𝐿𝐿𝑆𝑆 × 𝑂𝑂𝑐𝑐 𝜎𝜎𝑏𝑏 = 2 × 5,729.6 × 12 𝜎𝜎𝑏𝑏 ≅ 218 × 𝑂𝑂𝐿𝐿𝑆𝑆 × 𝑂𝑂𝑐𝑐 = 13,460 ft.-lbf 38 © Dr. Eric van Oort  Example 3 * Problem by Mitchell & Miska, 2011, Ch.9 39 © Dr. Eric van Oort Remember This Diagram when Designing a DS 40 © Dr. Eric van Oort  Example 3 – Solution I * Problem by Mitchell & Miska, 2011, Ch.9 41 © Dr. Eric van Oort  Example 3 Solution - Governing Equations Von Mises correction of maximum 𝐴𝐴𝑎𝑎 2 load capacity for torque 𝐷𝐷𝑎𝑎 = 𝐷𝐷 2𝑐𝑐−3 𝑇𝑇 𝑥𝑥 = 1, 2, 3 ….. 𝑍𝑍𝑎𝑎 First section of drillpipe 𝐹𝐹1 = 𝐿𝐿𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷 + 𝐿𝐿𝐻𝐻𝐻𝐻 𝑊𝑊𝐻𝐻𝐻𝐻 + 𝐿𝐿𝐷𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 𝐾𝐾𝑏𝑏 + 𝑀𝑀𝑂𝑂𝑀𝑀 𝐷𝐷𝐹𝐹 𝐷𝐷𝐷 𝐿𝐿𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷 𝐿𝐿𝐻𝐻𝐻𝐻 𝑊𝑊𝐻𝐻𝐻𝐻 𝑀𝑀𝑂𝑂𝑀𝑀 𝐿𝐿𝐷𝐷𝐷𝐷𝐷 = − − − 𝑆𝑆𝐷𝐷 × 𝐾𝐾𝑏𝑏 × 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 𝐾𝐾𝑏𝑏 × 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 Additional sections of drillpipe (in case LDC + LHW + LDPx < total depth of well) 𝐹𝐹2 = 𝐿𝐿𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷 + 𝐿𝐿𝐻𝐻𝐻𝐻 𝑊𝑊𝐻𝐻𝐻𝐻 + 𝐿𝐿𝐷𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 + 𝐿𝐿𝐷𝐷𝐷𝐷2 𝑊𝑊𝐷𝐷𝐷𝐷2 𝐾𝐾𝑏𝑏 + 𝑀𝑀𝑂𝑂𝑀𝑀 𝐷𝐷𝐹𝐹 𝐹𝐹2 𝐿𝐿𝐷𝐷𝐷𝐷 𝐻𝐻𝐷𝐷𝐷𝐷 𝐿𝐿𝐻𝐻𝐻𝐻 𝐻𝐻𝐻𝐻𝐻𝐻 𝐿𝐿𝐷𝐷𝐷𝐷1 𝐻𝐻𝐷𝐷𝐷𝐷1 𝑉𝑉𝑂𝑂𝐷𝐷 𝐿𝐿𝐷𝐷𝐷𝐷2 = − − − − 𝐷𝐷𝐹𝐹×𝐾𝐾𝑏𝑏 ×𝐻𝐻𝐷𝐷𝐷𝐷2 𝐻𝐻𝐷𝐷𝐷𝐷2 𝐻𝐻𝐷𝐷𝐷𝐷2 𝐻𝐻𝐷𝐷𝐷𝐷2 𝐾𝐾𝑏𝑏 ×𝐻𝐻𝐷𝐷𝐷𝐷2 42 © Dr. Eric van Oort  Example 3 – Solution II * Problem by Mitchell & Miska, 2011, Ch.9 2 𝐴𝐴𝑎𝑎 𝐷𝐷𝑎𝑎 = 𝐷𝐷 2𝑐𝑐−3 𝑇𝑇 𝑥𝑥 = 1, 2, 3 ….. 𝑍𝑍𝑎𝑎 𝐷𝐷𝐷 𝐿𝐿𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷 𝐿𝐿𝐻𝐻𝐻𝐻 𝑊𝑊𝐻𝐻𝐻𝐻 𝐿𝐿𝐷𝐷𝐷𝐷𝐷 = − − 𝑆𝑆𝐷𝐷 × 𝐾𝐾𝑏𝑏 × 𝑤𝑤𝐷𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 𝑊𝑊𝐷𝐷𝐷𝐷𝐷 𝐹𝐹2 𝐿𝐿𝐷𝐷𝐷𝐷 𝐻𝐻𝐷𝐷𝐷𝐷 𝐿𝐿𝐻𝐻𝐻𝐻 𝐻𝐻𝐻𝐻𝐻𝐻 𝐿𝐿𝐻𝐻𝐻𝐻 𝐻𝐻𝐻𝐻𝐻𝐻 𝐿𝐿𝐷𝐷𝐷𝐷2 = − − − 𝐷𝐷𝐹𝐹×𝐾𝐾𝑏𝑏 ×𝑤𝑤𝐷𝐷𝐷𝐷2 𝐻𝐻𝐷𝐷𝐷𝐷2 𝐻𝐻𝐷𝐷𝐷𝐷2 𝐻𝐻𝐷𝐷𝐷𝐷2 43  Example 3 – Solution III * Problem by Mitchell & Miska, 2011, Ch.9 DC’s HWDP DP1 DP2 Kb 44 © Dr. Eric van Oort DS Design Safety Margins Design based on Margin of Overpull (MOP) – Local experience / conditions – History of Stuck Pipe – Prediction of drag up values – MOP = Max. Allowable Tension Load - Calc. / Estm. Load Design based on Safety Factor (SF) – Commonly used SF is 1.15 (range typically 1.1 – 1.2) – SF = Max. Allow. Tension Load divided by Calculated Load (σyield / Fload) 45 © Dr. Eric van Oort Typical DS Design Safety Factors Tension SFT 1.15 Excess BHA weight SFBHA 1.15 Collapse SFC 1.125 Burst SFB 1.176 Margin of Overpull 50,000 to 150,000 lbs. Applied torsion is limited to make-up torque on connections 46 © Dr. Eric van Oort  Simple “Bottom Up” DS Design Process (Axial Loads only) Determine a desired Margin of Pull (MOP) Calculate the required length Include Design Factor (e.g. of DC’s and HWDP based on 1.2) for NP in BHA desired WOB Calculate the axial tensile load on the DS to surface, take into account torsion Consider Include appropriate Design Check axial load with API stronger pipe Factor (1.15) tensile strength of pipe to meet strength requirement Strength NO OK? YES 47 © Dr. Eric van Oort Finalize Design Application of Directional Drilling “To optimize the wellpath, geoscientists and (well) engineers must work together from the outset of the project” 48 © Dr. Eric van Oort  Basic Concepts – Inclination, Azimuth Segment A-B = Measured Depth (MD) or Along-Hole Depth (AHD) Vertical component of A-B = True Vertical Depth (TVD) Hole inclination measured as MD/AHD departure from vertical Hole azimuth measured as departure from North Angle between geographic (true) North and magnetic North is called declination angle Inclination (deviation) and azimuth characterized using survey tools, gyroscopic & magnetic tools Magnetic tools require the use of Monel drillcollars in the BHA 49 © Dr. Eric van Oort  Basic Concepts – Departure, Closure Departure is the horizontal distance between surface location and specific point on the trajectory (P2,P3,P4,P5) Closure is the horizontal distance between the rotary table and the center of the target box Horizontal projection displayed on North- East coordinate plot 50 © Dr. Eric van Oort  Vertical Section Derrick Floor RKB Rotary Kelly Bushing MSL Mean Sea Level SS Subsea Kick-Off Point (KOP) Build Rate (B) Tangent Section Deg/100ft 2nd KOP (DOP) Radius of Curvature (R) Drop-off Radius / Rate (R) TD Measured Depth – MD TD Along-Hole Depth - AHD Horizontal Displacement - HD 51 © Dr. Eric van Oort  Horizontal Section – Horizontal Displacement North Surface Azimuth Coordinates X Coordinate Value East Total Depth 2 2 TD 𝐻𝐻𝑂𝑂 = 𝑁𝑁𝑐𝑐𝑎𝑎𝑎𝑎𝑏𝑏𝑐𝑐𝑐𝑐 − 𝑁𝑁𝑠𝑠𝑚𝑚𝑎𝑎𝑠𝑠𝑎𝑎𝑐𝑐𝑐𝑐 + 𝐸𝐸𝑐𝑐𝑎𝑎𝑎𝑎𝑏𝑏𝑐𝑐𝑐𝑐 − 𝐸𝐸𝑠𝑠𝑚𝑚𝑎𝑎𝑠𝑠𝑎𝑎𝑐𝑐𝑐𝑐 52 © Dr. Eric van Oort  Horizontal Well Terminology Radius of Curvature (R) Radius of Curvature (R) Horizontal Lateral Section Horizontal Displacement (Horizontal Departure) 53 © Dr. Eric van Oort  The “Well Plot” - - - WELL PROFILE DATA - - - ---- Point - - - - MD Inc Dir TVD North East Deg/100 Tie on 0 0.00 261.47 0 0 0 0.00 KOP 1165 0.00 261.47 1607 0 0 0.00 End of Build 2090 37.02 261.47 1900 -43 -268 4.00 Target 2451 37.02 261.47 2305 -75 -500 0.00 End of Hold 3140 37.02 261.47 2490 -122 -800 0.00 West Scale 1 : 100.00 Survey calculations enable us 800 600 400 200 0 to plot the position of the 800 200 SURFACE LOCATION X = 2,658,408 Y = 112,566 borehole. - - - North : South - - - Scale 1 : 100.00 Scale 1 : 100,00 1000 0 AA This allows us to determine 1200 50’ RADIUS TARGET 200 the borehole’s position PBHL TARGET relative to the desired True Vertical Depth 2365”TVD 2490”MD 2305’ TVD 2451’ MD 1400 790’ AT 261.47 AZM 706’ AT 261.47 AZM KOP 1600’ MD S -122’ W -800’ X = 2.657,492 Y = 112.430 S -55’ W -379’ X = 2.657,902 Y = 112.491 position. 1600 BUILD 4/100’ MD Any discrepancy can then be 1800 adjusted for by reorienting the 2000 North 37.02 DEG drilling assembly. 2200 Mag to Grid corr AA TGT 2305’ TVD - 2451’ MD: 706’ SECT -9.0 Deg PBHL 2400 2365” TVD 2490” MD: 832” SECT 2600 200 0 200 400 600 800 Vertical Section on 261.47 azimuth with reference 0.00 N, 0.00 E from 11 54 © Dr. Eric van Oort  Dog Leg (DL) & Dog Leg Severity (DLS) Dog Leg is arc of circle of radius R; it is a length Dog Leg Angle = β or α; it is an angle Dog Leg Severity (DLS) = wellbore curvature in Kick Off R degrees / 100 ft (also referred to Point (KOP) β as Build Up Rate (BUR) when hole DL R angle is increased or Drop Off Rate (DOR) when hole angle is reduced) End of Build (EOB) Tangent Section 55 © Dr. Eric van Oort Right Hand Coordinate System Coordinate System x, y, z, consistent with North, East and Vertical (N, E, V) directions Element along the wellpath ds = (dx, dy, dz) Projection on horizontal plane of ds: dl = (dx, dy) 56 © Dr. Eric van Oort Dog Leg Severity (DLS) & Dog Leg (DL) 1 𝜅𝜅 𝑠𝑠 = , 𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤 𝑅𝑅 𝑠𝑠 𝐼𝐼𝑠𝑠 𝑅𝑅𝑎𝑎𝑎𝑎𝐼𝐼𝑌𝑌𝑠𝑠 𝑓𝑓𝑓𝑓 𝐶𝐶𝑌𝑌𝑤𝑤𝐶𝐶𝑎𝑎𝑠𝑠𝑌𝑌𝑤𝑤𝑤𝑤 𝑅𝑅(𝑠𝑠) 18,000 × 𝜅𝜅(𝑠𝑠) 5729.6 𝑂𝑂𝐿𝐿𝑆𝑆 = = 𝜋𝜋 𝑅𝑅(𝑠𝑠) with DLS in deg./100ft Δ𝑠𝑠 𝜑𝜑2 − 𝜑𝜑𝐷 𝜗𝜗2 − 𝜗𝜗𝐷 β = 𝜅𝜅 𝑠𝑠 𝑎𝑎𝑠𝑠 = 2 arcsin 𝑠𝑠𝐼𝐼𝑎𝑎2 + sin 𝜑𝜑𝐷 sin 𝜑𝜑2 𝑠𝑠𝐼𝐼𝑎𝑎2 2 2 0 For zero turn rate (T, H are zero, constant azimuth): Δ𝑠𝑠 𝜑𝜑2 β = 𝑊𝑊𝑎𝑎𝑠𝑠 = 𝑎𝑎𝜑𝜑 = 𝜑𝜑2 − 𝜑𝜑𝐷 𝜑𝜑1 57 © Dr. Eric van Oort0 WellPath Design – Special Case 1 𝑠𝑠2 ∆x = 𝑥𝑥𝐷 − 𝑥𝑥2 = sin 𝜑𝜑 𝑠𝑠 cos 𝜗𝜗 𝑠𝑠 𝑎𝑎𝑠𝑠 𝑠𝑠1 𝑠𝑠2 ∆y = 𝑆𝑆𝐷 − 𝑆𝑆2 = sin 𝜑𝜑 𝑠𝑠 sin 𝜗𝜗 𝑠𝑠 𝑎𝑎𝑠𝑠 𝑠𝑠1 𝑠𝑠2 ∆z = 𝑧𝑧𝐷 − 𝑧𝑧2 = cos 𝜑𝜑 𝑠𝑠 𝑎𝑎𝑠𝑠 𝑠𝑠1 Special Case 1: Wellpath for a curved wellbore confined to vertical plane 𝑎𝑎𝜗𝜗 = 𝑇𝑇 = 0 with constant azimuth 𝑎𝑎𝑠𝑠 𝑠𝑠2 cos 𝜗𝜗 𝜑𝜑2 ∆x = cos 𝜗𝜗 sin 𝜑𝜑 𝑠𝑠 𝑎𝑎𝑠𝑠 = sin 𝜑𝜑 𝑎𝑎𝜑𝜑 = ± 𝑅𝑅 cos 𝜗𝜗 cos 𝜑𝜑𝐷 − cos 𝜑𝜑2 𝑠𝑠1 𝑊𝑊 𝜑𝜑1 𝑠𝑠2 sin 𝜗𝜗 𝜑𝜑2 ∆y = sin 𝜗𝜗 sin 𝜑𝜑 𝑠𝑠 𝑎𝑎𝑠𝑠 = sin 𝜑𝜑 𝑎𝑎𝜑𝜑 = ± 𝑅𝑅 sin 𝜗𝜗 cos 𝜑𝜑𝐷 − cos 𝜑𝜑2 𝑠𝑠1 𝑊𝑊 𝜑𝜑1 ∆z = ±𝑅𝑅 (sin 𝜑𝜑2 − sin 𝜑𝜑𝐷 ) 𝐻𝐻𝑂𝑂 = ∆𝑥𝑥 2 + ∆𝑆𝑆 2 = 𝑅𝑅 cos 𝜑𝜑𝐷 − cos 𝜑𝜑2 58 © Dr. Eric van Oort  Example 65o 8.1 5729.6 5729.6 𝑅𝑅 = = = 882 𝑓𝑓𝑠𝑠 𝑂𝑂𝐿𝐿𝑆𝑆 6.5 ∆x = ± 𝑅𝑅 cos 𝜗𝜗 cos 𝜑𝜑𝐷 − cos 𝜑𝜑2 ∆y = ± 𝑅𝑅 sin 𝜗𝜗 cos 𝜑𝜑𝐷 − cos 𝜑𝜑2 ∆z = ±𝑅𝑅 (sin 𝜑𝜑2 − sin 𝜑𝜑𝐷 ) 𝐻𝐻𝑂𝑂 = ∆𝑥𝑥 2 + ∆𝑆𝑆 2 = 𝑅𝑅 cos 𝜑𝜑𝐷 − cos 𝜑𝜑2 This is the “dogleg” distance DL 59 © Dr. Eric van Oort WellPath Design – Special Case 2 𝑠𝑠2 ∆x = 𝑥𝑥𝐷 − 𝑥𝑥2 = sin 𝜑𝜑 𝑠𝑠 cos 𝜗𝜗 𝑠𝑠 𝑎𝑎𝑠𝑠 𝑠𝑠1 𝑠𝑠2 ∆y = 𝑆𝑆𝐷 − 𝑆𝑆2 = sin 𝜑𝜑 𝑠𝑠 sin 𝜗𝜗 𝑠𝑠 𝑎𝑎𝑠𝑠 𝑠𝑠1 𝑠𝑠2 ∆z = 𝑧𝑧𝐷 − 𝑧𝑧2 = cos 𝜑𝜑 𝑠𝑠 𝑎𝑎𝑠𝑠 𝑠𝑠1 Special Case 2: Wellpath for a curved wellbore confined to horizontal plane 𝑎𝑎𝜑𝜑 = 𝑊𝑊 = 0 at 90o deviation 𝑎𝑎𝑠𝑠 𝑠𝑠2 sin 90 𝜃𝜃2 ∆x = sin 𝜑𝜑 cos 𝜗𝜗 𝑠𝑠 𝑎𝑎𝑠𝑠 = cos 𝜃𝜃 𝑎𝑎𝜃𝜃 = ± 𝑅𝑅 sin 𝜃𝜃2 − sin 𝜃𝜃𝐷 𝑠𝑠1 𝐻𝐻 𝜃𝜃1 𝑠𝑠2 sin 90 𝜗𝜗2 ∆y = sin 𝜑𝜑 sin 𝜃𝜃 𝑠𝑠 𝑎𝑎𝑠𝑠 = sin 𝜗𝜗 𝑎𝑎𝜗𝜗 = ± 𝑅𝑅 cos 𝜗𝜗𝐷 − cos 𝜗𝜗2 𝑠𝑠1 𝐻𝐻 𝜗𝜗1 ∆z = 0 60 © Dr. Eric van Oort Typical 2-D Well Profiles “S”-shaped Build & Hold Well or Slant Well Continuous Build Well 61 © Dr. Eric van Oort  Unconventional Wells Casing Schemes DEM Onshore DEM Onshore CS#1 CS#2 Ground level Ground level Conductor Conductor TOC (Top of Cement) Surface casing Surface casing (optional multiple strings) TOC (Top of Cement) Intermediate casing Production Production Artificil lift String (optional) casing Artificil lift String (optional) casing Surface + Production Surface + Intermediate + Production Multiple surface casings possible Multiple surface or intermediate Normally pressured (TD MW12.5 ppg) Examples: Eagle ford Examples: Haynesville, Marcellus © Dr. Eric van Oort 62 Build & Hold / Slant and S-Shape Wells Preferred and most often used well type in the oil & gas industry whenever possible 63 © Dr. Eric van Oort Example 8.2 NOT subsea (SS), 180 ft But MSL R β 64 © Dr. Eric van Oort Example 8.2 – Cont’d 180 ft R β VD2 = 3,925 ft 180 ft s2 = 4,380 ft HD2 = 1,321 ft st = 7,403 ft 65 © Dr. Eric van Oort Example 8.3 66 © Dr. Eric van Oort  Example 8.3 – Cont’d 67 © Dr. Eric van Oort  Directional Drilling Systems Passive: Slick, Pendulum, Fulcrum & Stabilized Assemblies Semi-Active: Downhole Steerable Motors (SM – Turbines & PDMs) Active: Rotary Steerable Systems (RSS) 68 © Dr. Eric van Oort (Lack of) Deviation Control: Slick BHA String contacts low-side of hole at tangency point (assuming no buckling) WOB and side force Ho combine to create a resultant force R (pendulum effect) At low WOB, the BHA will tend to have a dropping tendency At higher WOB, the side force becomes nil and the resultant force aligns with hole inclination angle At high WOB, BHA is pushed towards high side of hole and may exhibit hole building tendencies Orientation of bedding planes will have large 69 © Dr. Eric van Oort influence on drilling direction  DrillingDeviation Components Control: Stabilizers Stabilizers – Can help maintain hole diameter (reaming stabilizer) – Can stabilize and centralize the drill collars, improve ROP and reduce differential sticking – Their exact placement / position in the string can profoundly influence deviation tendencies by controlling the side-force at the bit 70 © Dr. Eric van Oort  Factors Affecting Bit Trajectory Gauge and placement of stabilizers Diameter & length of (sections of ) drill collars Weight on bit Rotary speed Hole Gauge Bit type & bit gauge length Side Force at Bit Formation anisotropy and dip angle Resultant Side Force at Stabilizer Formation hardness Force at Bit Flow rate Hole Axis Formation Anisotropy Bit Tilt Angle Rate of penetration 71 © Dr. Eric van Oort Types of Directional Assemblies Drop Assemblies, using Pendulum Principle “Slick” assemblies use little to no stabilization, pendulum principle usually applies Build Assemblies, using Fulcrum Principle Hold Assemblies, using Stabilization 72 © Dr. Eric van Oort  Directional Drilling - Pendulum Principle © Dr. Eric van Oort  Pendulum Assemblies – Dropping Angle Maximum Dropping Tendency Increasing Dropping Tendency Minimum Dropping Tendency; UG = Under- Gauge stabilizer 74 © Dr. Eric van Oort Directional Drilling - Fulcrum Principle Directional Drilling – Fulcrum Effect 76 © Dr. Eric van Oort  Highest Building Fulcrum Response Assemblies – Increasing Building Tendency Building Angle Lowest Building Response; can be considered stabilized or dropping assembly 77 © Dr. Eric van Oort Directional Drilling - Stabilisation Principle 78 Stabilized Slightly Assemblies – Holding Angle dropping tendency Slightly building tendency 79 © Dr. Eric van Oort 30’ 30’ 30’ Downhole Motors (PDM’s) Positive displacement motors consist of: Dump or Bypass valve Power Assembly (rotor – stator) Connecting Rod / Universal Join Bearing or Drive Shaft / Sub Bit Sub 80 © Dr. Eric van Oort  The Motor Power Section The power section (Moineau motor) is a rotor combined with a stator. The motor has a helical rotor that turns inside a stator. The rotor and stator have a set number of lobes or “humps”. The lobes will wrap around in a circle, the length of which is the pitch The number of stator pitches define how long the motor will be and how much pressure drop will occur across the entire motor. Each stator pitch is called a stage. In the example below there are four stator pitches from end to end (four stage motor). 81 © Dr. Eric van Oort  The Motor Power Section The stator is a steel housing filed with an elastomer that is formed to have one more lobe than the rotor. The rotor is normally polished stainless steel. Because of the eccentricity of the rotor and stator, when mud flows through the stator, it imparts a torque on the rotor causing it to turn. The turning rotor passes fluid though the motor. The rotation of the rotor is passed through the transmission and bearings to the bit. 82 © Dr. Eric van Oort  PDM Power Generation – Moineau Rotor / Stator Green = rotor (steel) Number of lobes: LStator = LRotor + 1 Blue = stator (elastomer) ∆p = pressure drop across motor (psi) 𝜂𝜂 ∆𝑝𝑝 𝑄𝑄 5,252 𝐻𝐻𝑀𝑀 Q = mud flow rate (gal/min) 𝐻𝐻𝑀𝑀 = 𝑇𝑇 = © Dr. Eric van Oort 1714 𝑁𝑁 N = bit rotation speed (rev/min) 83 Steerable Motors PDM + Bent Sub (used in vertical hole for kick-off) PDM + Bent Housing (for hole angles > 20o) Typical bend angle 0o-3o, single or double-tilted MWD-unit sensor (survey unit) above motor used to measure downhole orientation (toolface orientation) 84 © Dr. Eric van Oort  Steerable Motors – Bent Housing 85 © Dr. Eric van Oort Build Rate The bent sub or motor housing places a small bend in the drill string. This small bend is an angle of between 1 to 3 degrees. The angle is used to cause the bit to travel in the direction it is pointed by the bent sub or motor housing. If a 1.5 degree bent sub is placed on top of a motor that is 30’ long, the maximum angle change (build rate) is – 1.5 δ= 100 ' = 5 /100 ' 30 ' Because the drill string is flexible, the farther back the bend, the more it can be constrained by the bore hole. Moving the bend closer to the bit creates a larger theoretical build rate. 1.5 δ= 100 ' = 18.75 /100 ' 8' This is one advantage to using a bent motor housing just on top of the bit. This also creates a much stiffer assembly that will not be constrained by the flexibility of the drill string in the bore hole. The large theoretical angle change also allows for shorter slide lengths to 86 achieve a desired angle change. © Dr. Eric van Oort  Cross-Borehole References High Side A High Side Left Right A Rolling Ball Rolling Ball Low Side Low Side Vertical View “A-A” 87 © Dr. Eric van Oort  High-side (Gravity) Tool-face High-side High-side Left Right Left Right Low-side Low-side Tool-face = 0 degrees Tool-face = 180 degrees Building angle while Dropping angle while maintaining azimuth maintaining azimuth 88 © Dr. Eric van Oort  High-side (Gravity) Tool-face High-side High-side Left Right Left Right Low-side Low-side Tool-face =90 degrees Tool-face = 300 degrees Maintaining angle while Building angle and turning to the right turning to the left 89 © Dr. Eric van Oort  Slide Steering - I The slide drilling procedure is : Determine the new tool face angle to move in the correct direction. Turn the tool face to the correct setting and engage the pumps. The mud flowing through the motor will cause the bit to turn. The drill pipe is not rotated at this time so that the tool face angle is not changed. The drill pipe is lowered as the weight on bit is drilled off and the drill string is sliding along as the bit drills. The tool face angle is monitored to insure it does not change during the slide (correction for reactive torque!!!). After sliding for some distance (as short as possible) new measurements of inclination and azimuth are made to see if the hole is changing course as desired. If it is not, sliding is continued until the course change is occurring. 90 © Dr. Eric van Oort  Slide Steering - II Overcoming friction and getting weight to the bit is a constant battle that requires special measures: lubricants & “torque rocking” Once a slide of sufficient length has been made to create the direction change, the entire drill string is rotated along with the bit rotation caused by the motor. Now the tool face is being rotated and cannot move the bore hole in any direction other than what has been previously set. Drilling can now proceed while rotating to the next survey point. 91 © Dr. Eric van Oort  Automated Directional Drilling Instructions from Directional Drillers for Toolface Toolfaces from MWD Drillers Scoring Torque Indicators Rockit Controls Rockit Controls Delta Pressure Integrated Slide Drilling Controls to the Top Drive Rig outperform the Competition © Dr. Eric van Oort  Steerable Motor / MWD System Inclination & Azimuth Resistivity Measurement Neutron Gamma Ray Density Multiple depths of investigation for quantitative determination of formation resistivity (Rt) Early bed boundary detection A near bit inclinometer, enabling quick response to inclination changes A steerable motor system, permitting variable build rates for up to 15°/100 ft Resistivity measurements available in either oil base or water base muds Dual azimuthal gamma ray sensors 180° apart, providing high and low side measurements. 93 © Dr. Eric van Oort Steerable Motors – Slide & Rotary Drilling Sliding: drillstring is not rotating, changes to inclination and azimuth are accomplished by reorientation of bent housing / toolface Rotating: directional effect of bent housing is negated / averaged out, and bit drills slightly over-sized hole Negatives of slide drilling: poor axial-force transfer to bit, poor hole cleaning / cuttings transport, differential sticking risk, irregular hole with micro-doglegs, intervals of rotary drilling interspersed with intervals of (slower) slide drilling, etc. 94 © Dr. Eric van Oort Example of Slide – Rotate Sequence 95 © Dr. Eric van Oort Rotary Steerables (RSS) Push-the-Bit Steers by applying a sideload to the bit, usually using pads close to the bit to apply this load Forces the bit’s outer cutting structure and gauge to cut sideways into the formation and drill a curved hole in the selected direction; Requires short gauge bits ( P2 > P3 Bit Side Force = P3 P1 Rotating Shaft Magnitude Hybrid System: can work in both “Push-the-Bit’ and “Point-the-Bit” modes 98 © Dr. Eric van Oort  Essence of Casing Design 1. Loads acting upon the casing strings during: – Drilling – Completion / Stimulation – Workover / Re-completion – Production – Abandonment / Decommissioning 2. Load-bearing capacity provided by the casing strings under various circumstances – Temperature – Wear / Corrosion – Presence of Sour Gases © Dr. Eric van Oort – Etc. 99  Casing Program Nomenclature Subsea Well Land Well Foundation Pile Conductor (30”) (13 3/8”) Conductor (20”) Surface Casing (9 5/8”) Surface Casing (13 3/8”) Intermediate Casing (7 5/8”) Intermediate Casing (9 5/8”) Production Casing (5”) Drilling Liner (7 5/8”) Production Liner Production Casing (Optional) © Dr. Eric van Oort (5”) © Dr. Eric van Oort 100 Types of Casing & Utility Type of Casing Purpose Foundation Pile, Structural support Drive / Stove Pipe Conductor Isolation, shallow gas protection, structural support Surface Isolation of ground water, pressure control, build section coverage Intermediate Borehole stability, isolation of (low) pressured or producing zones Production Isolate producing zone, tubing leak protection, injection, gaslift Liners Local isolation and protection, borehole stability Tiebacks Convert liners into full strings to wellhead (with extra seal/barrier) Utility of Casing Structural support for wellhead, other tubulars Barrier to pore pressure and flow of formation gas & fluids to surface Isolation and stabilization of formations Control of well pressures during drilling, completion, production and intervention © Dr. Eric van Oort 101 Casing Program Example: Onshore US Conductor Casing Structural Pipe Surface Casing Isolates groundwater Could be multiple strings Intermediate Casing Required when drilling into pressures Production Casing © Dr. Eric van Oort 102  Casing Design = Barrier Design Conventional Cemented Completion Secondary Barrier Production Casing Primary Barrier Production Tubing and Packer Secondary Barrier Intermediate or Surface Casing Primary Barrier Production Casing © Dr. Eric van Oort 103 Yield & Tensile Strength of Casing Data in API Standards 5C2/5C3 Pipe Grade designated by letter and number (e.g. K55, L80, P110) Letters somewhat arbitrary, may indicate certain metallurgy Numbers indicate Minimum Yield Stress (in 103 psi) to generate 0.5% (0.65%) strain: K55 = 55,000 psi Yield Stress Tests performed at 24 deg. C © Dr. Eric van Oort 104 API Casing Grades API Grade API Yield Strength API Yield Strength Minimum Tensile Minimum (psi) Maximum (psi) Strength (psi) J55 55,000 80,000 75,000 K55 55,000 80,000 95,000 L80 80,000 95,000 95,000 C90 90,000 105,000 100,000 C95 95,000 110,000 105,000 T95 95,000 110,000 105,000 P110 110,000 140,000 125,000 Q125 125,000 150,000 135,000 𝜎𝜎𝑦𝑦𝑎𝑎𝑐𝑐𝑎𝑎𝑚𝑚 © Dr. Eric van Oort 105 Effect of Environment Temperature has a strong effect on mechanical properties Yield strength, tensile strength, stiffness decrease, ductility increases with increasing temperature; pipe strength therefore has to be de-rated for temperature (particularly during production phase) Toughness affected by cold(er) temperatures, requiring Charpy testing at coldest anticipated service temperature Presence of gases such as H2S and CO2 can reduce toughness of steel, necessitates use of special alloys (for instance Cr3+-doped) © Dr. Eric van Oort 106 Casing Design Considerations Human lives and the environment are at stake – failures can be catastrophic !!! Loads on the system need to be determined and properly modeled The system’s behavior under different loads must be modeled and controlled Mechanical equipment properties must be understood, including deformation under the loads Operational limits need to be set and 𝜎𝜎𝐿𝐿𝑐𝑐𝑎𝑎𝑚𝑚 × 𝑂𝑂𝐷𝐷 < 𝜎𝜎𝑌𝑌𝑎𝑎𝑐𝑐𝑎𝑎𝑚𝑚 communicated; safety margins / design factors (DF) need to be included 𝜎𝜎𝑌𝑌𝑎𝑎𝑐𝑐𝑎𝑎𝑚𝑚 The condition/fitness of the equipment 𝜎𝜎𝐿𝐿𝑐𝑐𝑎𝑎𝑚𝑚 < needs to be monitored and maintained; 𝑂𝑂𝐷𝐷 changes will affect ability to withstand the loads 107 © Dr. Eric van Oort Design Philosophy - Working Stress Working-Stress: maximum load + minimum resistance, with safety factors built in Assume worst Maintain separation between worst case Derate casing case loads (stress) strength with acting on casing load and derated 108 © Dr. Eric van Oort strength suitable design factor  Loads / Forces on Casing Load Sources: Weight & Buoyancy Fluid Pressures (Pore Pressure, Mud, Cement) Formation Stress (e.g. Salt) Temperature (particularly during production) Production-Induced Compaction, etc. Load Types: Axial Tension & Compression Pressure (Burst or Collapse) Bending Torsion & Shear Failure Types: Axial Tension Burst Collapse Tensile Running Torsion/Shear Failure (Twist-off) 109 © Dr. Eric van Oort Casing Failure Example Uniaxial Tension / Compression Uniaxial Burst (Barlow Equation) Uniaxial Collapse – zero internal pressure Uniaxial Collapse – non-zero internal pressure Biaxial Collapse – collapse & tension loads Triaxial Burst (von Mises Equation) Load Case Stresses Considered Uniaxial Tension / Compression σa Uniaxial Burst σr Uniaxial Collapse σr Biaxial Collapse σr , σa Triaxial Burst σr , σa , σθ  Types of Casing Failure: Burst Pipe burst occurs when the pressure in the inside of the pipe (Pi ) exceeds the pressure on the outside of the pipe (Po) by such an amount to exceed the API Yield Stress of the material 111 © Dr. Eric van Oort Surface & Intermediate Load Cases - Burst External Internal Pressure Pressure Full / partial displacement GAS of casing to gas during shut-in Gas kick kill operation Pressure testing of casing GAS GAS GAS Po Pi-Po Pi 112 © Dr. Eric van Oort Uniaxial Burst Calculations Barlow Equation for internal pressure resistance (12.5% wall-thickness tolerance): Calculate API Burst Resistance of 20”, K55 casing, 0.635” wall thickness, 133 lb/ft 113 © Dr. Eric van Oort Casing Point Selection Casing points determined by: Regulatory Requirements Shallow aquifers using for drinking water / agriculture (with surface casing) Production zone coverage (casing & cement requirements) PPFG Pressure Limitations Kick tolerance: ability to handle a kick of a certain size and intensity safely within the available formation strength / MASP Geological Motivation: “casing-off” particular formations / hole sections Shallow water flow zones and other high-pore-pressure zones Depleted zones (e.g. before entering normal / high pressure zones) Unstable zones, loss zones, faults, brecchiated zones etc. Salt, Tar zones, etc. © Dr. Eric van Oort 114 “Top-Down” Casing Point Selection Pressure Two limits to the density of the drilling fluid: Gradient vs. Hydrostatic pressure exerted by the fluid must Depth graph! be greater than the pore pressure to prevent influxes form occurring Hydrostatic pressure exerted by the fluid must be less than the “formation strength” to prevent formation fracturing and associated mud losses It is normal to establish a safety margin / trip margin on the limiting values (e.g. 200 psi or 0.5 ppg above pore pressure and below formation strength) It is preferable (but not always possible due to limited drilling margins) to maintain a riser margin for subsea wells This simple method does not explicitly consider the effect of circulating out a gas kick © Dr. Eric van Oort115 Example of a top-down design Source images: drillingformulas.com © Dr. Eric van Oort (Un)limited Kick Design, “Bottom up” © Dr. Eric van Oort 117  “Bottom-Up” Casing Point Selection Pressure vs. Depth graph! Bottom-Up / Unlimited Kick Design: Considers situation where kick is taken at a given point (usually section TD), and kick is not shut in until entire open hole annulus is evacuated to gas Pressure at previous shoe becomes: 𝑀𝑀𝐷𝐷𝑆𝑐𝑐𝑐𝑐 = 𝑀𝑀𝑐𝑐 − 𝑂𝑂𝐾𝐾𝑎𝑎𝑐𝑐𝐾𝐾 − 𝑂𝑂𝐷𝐷𝑆𝑐𝑐𝑐𝑐 × 𝜌𝜌𝐼𝐼𝑐𝑐𝑠𝑠𝑎𝑎𝑚𝑚𝑎𝑎 Note that pressure at the shoe increases as density of the influx decreases, and reaches a maximum equal to the reservoir pressure at TD for an assumed influx density of zero (ρinflux = 0, Pshoe= Po) If the formation strength at the shoe would be exceeded during a well control event, this would result in an underground blowout © Dr. Eric van Oort118 Design Process: “Bottom-Up” Casing Point Selection Pressure © Dr. Eric van Oort 119 Design Process: Conventional Casing OD Selection © Dr. Eric van Oort120  The Value of Cementing Cementing 3-5% of total well cost (industry wide), however…. Failures have high impact on completions, productivity, environment and cost over the life the well Often very expensive or impossible to effectively remediate a poor primary cement job -> well may be junked As strange as it may seem, the idea of cementing the casing-wellbore annulus was neither intuitive nor easily accepted. In 1919, most operators were skeptical of cementing casing. Most wells were doing well, they reasoned, without the new-fangled technology…. “Cementing is not for sissies” Hart E&P Magazine, May 1, 2007 121 © Dr. Eric van Oort  Casing Cementation: Cement (Dis-)Placement 122 © Dr. Eric van Oort  Liner Cementation 123 © Dr. Eric van Oort Cement Evaluation: Bond Logging 124 © Dr. Eric van Oort  Cement CBL/VDL Evaluation Top of Cement 125 © Dr. Eric van Oort Cementing Problems 126 © Dr. Eric van Oort Casing Centralization 127 © Dr. Eric van Oort Cementing Optimization (If Possible) 1. Mud Conditioning 2. Pipe Rotation 3. Standoff 4. Turbulent Flow 128 © Dr. Eric van Oort Cement Composition ID Mineral % Mass Characteristics C3S Tri-Calcium Silicate 40-65% Contributes to all stages of compressive strength development C2S Di-Calcium Silicate 16-54% Contribute to final strength only C3A Tri-Calcium