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Drilling Hydraulic of Compressible and In-compressible Drilling Fluid

Incompressible Fluids
1. static Well Conditions
• Hydrostatic Pressure in Liquid Columns
• Hydrostatic Pressure in Mixed Columns
• Kick Identification
• Buoyancy and Effect of Buoyancy on Buckling
2. Non-static Well Conditions
• Flow Through Jet Bits
• Shear Stress V.S. Shear Rate (Laminar)
3. Rheological Models
• Newtonian
• Non-Newtonian
• Rotational Viscometer
• Initial Circulating of Well
4. Laminar Flow In Pipes & annulus
• Newtonian Flow In Pipes & annulus
• Newtonian Flow In Pipes & annulus (As a Slot)
5. Turbulent Flow In Pipes & annulus
• Moody Diagram
• Critical Velocity
• Hanks Turbulence Criterion
6. Extension Equations For Flow
• Hydraulic Radius
• Apparent Viscosity
7. Jet Nozzle Size Selection
• Pressure loss Simplification
• Maximum Nozzle Velocity
• Maximum Bit Hydraulic Horsepower
• Maximum Jet Impact Force
• Minimum needed annular Velocity
8. Surge and swab pressure of Vertical Pipe Move
9. Particle Slip Velocity
10. Known Cleaning Needs

Compressible Fluids
11. Basic Technology
• Introduction
• Surface Equipment
• Down hole Equipment
• Compressors
• Shallow Well Drilling Applications
12. Circulation Systems
• Reverse Circulation
• Direct Circulation
13. Comparison of Mud and Air Drilling
• Pressure profile
• Heat capacity
• Density profile
• Kinetic energy profile
14. Surface Equipment Summery
• Drilling Location
• Flow Line to the Rig
• Wellhead Equipment
• Flow Line from Rig
15. Downhole Equipment Summery
• Rotary Drill String
• Drill Bits
• Bottom hole Assembly
• Drill Pipe
• Safety Equipment
• Drill String Design
16. Compressors type Nominations
• Continuous Flow
• Intermittent Flow
17. Power Requirements
• Single Stage Shaft
• Multistage Shaft
• Prime Mover Input
18. Reciprocating Compressor Unit
19. Shallow Well Drilling Applications
• Shallow Well Drilling Planning
• Direct Circulation
• Reverse Circulation
• Direct Circulation Based on Weight Rate of Flow
• General Derivation
• Wet and Dry Air and Gas Drilling Model
• Unstable and Stable Foam Drilling
• Aerated Fluid Drilling Model
20. Direct Circulation Hydraulic Sections
• the injection pressure into the top of the drill string
• pressure at bottom of drill pipe inside the drill string
• pressure at bottom of drill collars inside the drill string
• pressure above drill bit inside the drill string
• pressure at bottom of drill collars in the annulus
• pressure at bottom of drill pipe in the annulus
• pressure at the bottom of casing in the annulus
• pressure at the top of the annulus
21. Air and Gas Drilling Models
• Deep Well Drilling Planning
• Minimum Volumetric Flow Rate
• Terminal Velocities
• Injection Pressure and Selection of Compressor Equipment
• Prime Mover Fuel Consumption
• Water Injection
• Drilling and Completion Problems
22. Major & Minor Loss & Injection Pressure
• Non-Frictional Approximation
• Frictional Approximation

  • Sé el primero en comentar

Drilling Hydraulic of Compressible and In-compressible Drilling Fluid

  1. 1. Advance Drilling Engineering Drilling Hydraulics Amir Rafati In The Name of God
  2. 2. Drilling Hydraulics 1. Hydrostatic Pressure in Liquid Columns RankineT gallbm ftD psiP ePPGases PDPLiquids zT DDM n i ii : /: : : 052.0 1544 )( 0 0 1 0 ρ ρ − = =⇒ +=⇒ ∑
  3. 3. Drilling Hydraulics 2. Hydrostatic Pressure in Mixed Columns MWAVEM RTzNp pMN galMoleN p RTzN p RTzN f fff v vf fgv v v g gggf n i ii .: )( /: 1 )1( 1 + + = + = +−== ∑= ρ ρ ρρρρ
  4. 4. Drilling Hydraulics 3. Hydrostatic Pressure in Mixed Columns TRzNbMNa p p a b a pp DD dp pMN RTzNp dD dDdp RTzNp pMN vvf p p vf v D D v vf =+= + − =− + + = = + + = ∫∫ )(052.0 ln )(052.0 )( 1 212 12 2 1 2 1 ρ ρ ρ ρ ρ
  5. 5. Ex. Drilling Hydraulics min/350.875.9/50 /9/9.21/14 12000.6207.03.02.0 galQinDhrftROP gallbmgallbmgallbm ftPosBitRTSS mudbit WaterSolidmud o gw === === ===== ρρρ φ gallbmgalV galV galV galV psip PenGas PenWater PenSolid PenBit /057.14 2.065.2350 )2.0(9)65.2(9.21)350(14 min/464.0)7.0)(2.0(31.3 min/2.0)3.0)(2.0(31.3 min/65.2)2.01(31.3 min/31.3 60 48.7 )144(4 )875.9( 50 8751)12000)(14(052.07.14 . . . 2 . = ++ ++ = ⇒      == == =−= =            = =+= ρ ρ π
  6. 6. Ex. Drilling Hydraulics gallbmgalVgalV PenGasPenBit /057.14min/464.0min/31.3 .. === ρ 12000148716 14139.131000 7197.13500 3654.13250 09.77.14 1200037.100119008716 1197834.100118788700 1204643.100119468750 ln72.15 7312.0 5.11)620)(3.80)(000231.0(17312.0)]000231.0(16057.14[052.0 /000231.0 350 081.0 min/081.0 16 )464.0(8.2 /8.2 )620)(1(3.80 )16)(751.8( 16 12 1 212 2 DP DD p ppp p ba galmolNmolgasflowMole gallbmMW v Gas ρ ρ ⇒         − − ===+= ==== ===
  7. 7. Drilling Hydraulics 4. Kick Identification StoppingpumpbeforeectionKickt mudmkickk qtGV L PP PDLLDP CapacityAnnularC VolumeVLengthL C C L VLLCVL d dk k dpc mk dpmkkkmc kkkk det: :: 052.0 ])([052.0 : :: )( 2 3 3 33 += − −= =−+−+ −+== ρρ ρρρ
  8. 8. Drilling Hydraulics 5. Buoyancy WOBF CollarDrilloflengthWeightw FApxwFFWWF WWWeighteffectiveW FWWgVF b dc bdcdcbT s m ee boesmbo : /: 1: 22221 −−=−−+=       −= −== ρ ρ ρ
  9. 9. Drilling Hydraulics  Effect of Buoyancy on Buckling Neutral point must be located on Drill collar dc bitdcdc dpn n w Fxw xX X X − += > )(XSurfacefrom pointNeutralofDistance: dpn dcbdpT WFORWF <>− 0
  10. 10. Drilling Hydraulics  Effect of Buoyancy on Buckling. Neutral point must be located on Drill collar else buckling Happens.       − = s f dc bit dc w F L ρ ρ 1 L Bit WeightaforRequiredCollars DrillofLengthMinimum: dc
  11. 11. Drilling Hydraulics 6. Non-static Well Conditions: Bernoulli Equation: Losses g VP ZGains g VP Z +++=+++ 22 2 22 2 2 11 1 γγ
  12. 12. Non-static Well Conditions 7. Flow Through Jet Bits bdj b dn j pqCF p CV vQ v t m t mv Funitfieldin ∆= × ∆ = =∆      ∆ = ∆ ∆ = − ρ ρ ρ 01823.0 10074.8 )60(17.32 )()( : 4
  13. 13. Non-static Well Conditions  Shear Stress V.S. Shear Rate (Laminar) dL dV A F ModelNewtonianIn RateShear dL dV StressShear A F dL dV A F dL dV A F µ γ τ µ = = = =⇒∝ : : :
  14. 14. Non-static Well Conditions 8. Rheological Models 8.1. Newtonian 8.2. Non-Newtonian 2.1. Bingham Plastic Model 2.2. Power Law Model 2.3. Modified Power-Law Model
  15. 15. Rheological Models 0 0 .5 .4 )1(.3 .2 )1(.1 τγτ τµγτ γτ µγτ γτ += += >= = <= n n n K nforK nforK
  16. 16. Rheological Models Shear Rate Dependent Vis. Time Dependent Viscosity Non Newtonian Models:
  17. 17. Rheological Model Calculations 9. Rotational Viscometer 2 )2( 5.360 )2(5.360 : rh rrhTT dr d r dr dv Soslippingoneffectnohas dr d r dr dv rv spring slip π θ τ πτθ ω γ ω ω ω ω = == == +==
  18. 18. Rheological Model Calculations  Rotational Viscometer: Newtonian Model N N TableViscometerfromngSubstituti r N r N dr d r rrh r dr h d rhdr d rhdr d r N r r 703.1& 300 : 066.5 )04137.0( 60/4 11 )2( 5.360 )2( 5.360 )2( 5.360 )2( 5.360 23 2 2 2 12 3 0 3 2 2 1 2 == ===       −= == === ∫∫ γ θ µ πω γ ωπ θ µ µπ θ ω µπ θω π θ τ ω µµγτ ω
  19. 19. Rheological Model Calculations  Rotational Viscometer: Bingham Model    −= −= ⇒      −= −= −= −      −= −= −=+= ∫∫∫ 600300 300600 600 300 1 2 2 2 2 1 2 3 0 3 2 600 300 600 300 300 300 300 300 300300 : ln 11 )2( 5.360 )2( 5.360 )2( 5.360 2 1 2 1 2 θθτ θθµ τ θ µ τ θ µ τ θ µ µ τ µπ θ ω µ τ µπ θ ω µ τ µπ θω γµττ ω y p yp yp y N p p y p r rp y r rp p y p py NN TableViscometerfromngSubstituti r r rrh r dr r dr h d rrhdr d
  20. 20. Rheological Model Calculations  Rotational Viscometer: Power-Law Model         − =              −            =       = =      =      == ∫∫ + nn n nn n r r n n n n n n rr n hK rr n hK r dr hK d hrdr d Kr hrdr d rKK /2 2 /2 1 2 /1 /2 2 /2 1 /1 2 )1/2( /1 0 2 2 11 2 )2( 5.360 11 2)2( 5.360 )2( 5.360 )2( 5.360 )2( 5.360 2 1 2 ω π θ π θ ω π θ ω π θω π θ τ ω γτ ω ( )n N N N nn n N K N N n rr n r N dr d r 703.1 510 log log 11 1 2094.0 1 2 /2 2 /2 1 /2 1 2 θ θ θ ω γ = =         −       ==
  21. 21. Drilling Hydraulics  Laminar Flow In Pipes & annulus  Assumptions: Drill string is placed Concentrically Drill string is not being Rotated Open hole is Circular with known Diameter Drilling fluid is Incompressible The flow is Isothermal
  22. 22. Laminar Flow In Pipes & annulus [ ] [ ] [ ] r C dl dpr rdr dl dp rd dr rd rdl dp rlrrr dr d lrl dl dp prrprrF VelocityConswithlrrr dr d lrrFlrF rrl dl dp prrpFrrpF i i rr 1 4 1 43 221 2 )(0 )(1 00)(2 )2()2()2(:0 :.)(2 )(2)2( )2()2()2( +=⇒=⇒=− →∆=∆∆+      ∆+− ∆+      ∆−∆−∆= ∆∆+      ∆+ =∆∆+=∆= ∆      ∆−=∆=∆= ∫ ∫ ∑= ∆+ ττ τ π τ τ πτππ π τ τ πτπτ πππ
  23. 23. Newtonian Flow In Pipes & annulus       − −+ = = → − −+ = −=       −−−= = → ∫ ∫ )(ln 1500 : 8 )(ln 8 )( )(ln )(ln )()( 4 2 )2( 12 2 1 2 22 1 2 2 2 0 12 2 1 2 22 1 2 2 2 1 2 2 12 22 1 2 2 22 2 1 2 1 dd dd dd v dl dp unitfield r v dl dp rr rr rr v dl dp vrrQ dr rr rr rrrr dl dp Q drrvQ r r r µ µµ π µ π π
  24. 24. Newtonian Flow In Pipes & annulus (As a Slot) ( )2 00 0 0 2 0 4321 124 321 2 1 2 ,0:0 2 00: )( yhy dL dp v dL dph vy v y dL dpy v dL dp y dy dv dy d dL dp FFFFflowSteadyIn rrhWhALWy dy dr F LWFyWL dL dp pFypWF −= −=== +−−= +=−= =−⇒=+++ −==∆      ∆+= ∆=∆∆−=∆= µ τ µ τ µ τµτ τ τ τ
  25. 25. Newtonian Flow In Pipes & annulus (As a Slot) ( ) ( ) 2 12 2 12 2 12 2 12 2 12 2 1 2 2 3 0 2 212 )(1000 :)Laminar( )( 12 )(1000 : )( 12 ))(( 1212 2 2 )( , 2 1 dd Lv punitfieldflowin rr Lv p dd v dL dp unitfield rr v dL dp rrrr dL dp dL dpWh q dyyhy dL dpW vWdyvdAq rr Wyhy dL dp v ff h − =∆ − =∆ − = − = −−== −=== + =−= ∫ µµ µµ µ π µ µ µ
  26. 26. Turbulent Flow In Pipes & annulus flowTurbulentif flowTurbORTeransientif flowLamif flowLamCompletelyif Dv unitfield Dv :4000Re .:4000Re2100 .:2100Re .:1200Re 928 Re:Re > << < < == µ ρ µ ρ
  27. 27. Turbulent Flow In Pipes & annulus dl dp v D Av l dl dp fvEl dl dp lrF lrA dl dp dl dp r r C dl dp where wwwk ww 22 2 2 2 1 k k k k 2 2 1 4 D : 2 1, 4 D )2( 2, 4 D : 2 r 0:0, 2 r fluidofmeunit voluperenergyKinetic:E conduittheofareaticCharactris:A Movementfluidtoduellconduit waonexertedForce:F : AE F f:asDefinedisfactorFriction ρρ π ρ π τπ πττττ = ∆ ==∆=∆= ∆===⇒==+= =
  28. 28. Turbulent Flow In Pipes & annulus ( ) .* )000,100Re2100&( Re 0791.0 )(395.0Relog4 1 .)( Re 255.1 D 269.0log4 1 * :followsasCalculatedbeTurbulCan ) D Re,(f:flowTurbulentIn Re 64 f:flowLaminarIn 25.0 DiagramMoody RoughnessZerof RoughnessZerof f EqsColebrooke ff f <<= −=         +−= == ε ε
  29. 29. Moody Diagram:
  30. 30. Turbulent Flow In Pipes & annulus )000,100Re2100&( 1800 928 8.25 0791.0 : Re 0791.0 :unit)(fieldflowTurbulentIn 128Re 64 2 : Re 64 :flowLaminarIn 8.25 : 2 : 2 25.1 25.075.175.0 25.0 2 25.0 2 2 22 2 <<=         == === === RoughnessZero d v dl dp Dv D v dl dp f D v D v dl dp f D vf dl dp unitfield D fv dl dp dl dp v D f µρ µ ρ ρ µ ρ ρρ ρ
  31. 31. Turbulent Flow In Pipes & annulus  Critical Velocity Can be Defined instead of Re:  If V be Greater than Critical Velocity then turbulent flow will be formed.  Else Laminar flow will be Predicted.  Amount of Re is somehow Arbitrary. D v Dv c ρ µ µ ρ 26.2928 2100:2100Re =⇒==
  32. 32. Extension Eqs. For Flow In annulus  Hydraulic Radius: ( ) ( ) ( ) )(ln1500 )(ln 1500 816.0 10001500 4 4)(2 )( 12 2 1 2 22 1 2 22 12 2 1 2 22 1 2 2 122 12 2 12 12 21 2 1 2 2 dd dd ddd d v dd dd dd v dl dp ddd dd v d v dl dp ddrd dd rr rr S A r e e e e He H − −+=⇒=       − −+ = −=⇒ − == −== − = + − == µµ µµ π π
  33. 33. Power Law & Bingham Models  Apparent Viscosity: Apparent Viscosity is Defined Because of viscosity definition in Re but it can be defined when it is assumed that an imaginary fluid with the same pressure loss is assumed.
  34. 34. Apparent Viscosity ( ) nnn n n a n n n a nK vn v Kd n d vK d v       + =⇒      + =       + = − − − + /13 0416.089100 Re 0416.0 /13 96 0416.0 /13 1440001500 )2( )1( )1( )1(2 ρ µ µ  Bingham Model:  Power Law Model: ( ) ( ) v dd v d dd v d v y pa y pa ypa )(566.6 22515001500 12 22 − +=+= += τ µµ τ µµ τµµ
  35. 35. Hanks Turbulence Criterion for Bingham Plastic Model Parameters Den. V d PV YP Units: 3 / Lm tL / L Ltm/ 2 / Ltm DefinedbeCanGroupDimNon .2:235 −=− ( ) He w y w y w y cr He w y w y p y He NN Nd N             +      − = =       −       = τ τ τ τ τ τ τ τ τ τ µ ρτ 8 3 1 3 4 1 16800 1 37100 4 Re 32 2
  36. 36. EX. Hanks Turbulence Criterion for Bingham Plastic Model ( ) ( )        = ∆ =∆ ==∆=∆=∆    =⇒= ⇒>⇒      == =⇒= ==⇒>===−= =+= − +== − = − = psi D lv P psil D vf l dl dp P f FlowTurb NNDv N NN D N Dv NinddD v dd dd Q v e p f e f f cr p e crHe p ey He a e e y pa 289 1800 .2 289 )632.1(8.25 )1000()14.11)(10(0098.0 8.25 .1 0098.04218Re . 4218 928 33009263 9263 37100 21003154 928 632.1)(816.0 5.53 14.11 )2)(15(5 40 )(5 14.11 )5.45.6(448.2 600 )(448.2 25.1 25.075.175.0 22 ReRe Re Re 2 2 Re12 12 222 1 2 2 µρ ρ µ ρ µ ρτ µ ρ τ µµ ?5.4100/1540 10005.6min/600/10 . =∆=−== ==== fricDC Well PinODftsqlbfYPcpPV ftLinODgalQgallbρ
  37. 37. Initial Circulating of Well  Because of Thixotropic behavior of mud when circulation started: instead of shear stress, known gel strength can be used so: ( ) )(300 : 300 :) 100 :( 22 12 2 12 dddl dp annulusfor ddl dp ft lbunitfield dl dprr dl dpr gg g g w g − == − == ττ τ ττ
  38. 38. Pressure loss Simplification m tb bft adcfadpfdcfdpff m f m f cQPP PPP PPPPP DiaDenVislfc cQPQP −∆=∆ ∆+∆=∆ ∆+∆+∆+∆=∆ ∆= =∆⇒∝∆ .... .).,.,,(
  39. 39. Jet Nozzle Size Selection  Maximum Nozzle Velocity  Maximum Bit Hydraulic Horsepower  Maximum Jet Impact Force  Minimum needed annular Velocity
  40. 40. Maximum Nozzle Velocity  It happens when maximum pressure loss in bit-nozzles happens and minimum pressure loss happens in pipes that means minimum flow rate is occurred in pipes and annulus.  It helps cutting-removals around cutters of bit.
  41. 41. Maximum Bit Hydraulic Horsepower ( ) [ ] [ ] tbtb t f ft m t m tHP m t m tb HP m tb PPmP m m P m P P PmP cQmP cQmP dQ dP cQQPQcQPQP PcQPP ∆×∈∆∈∆ + =∆ + ∆ =∆ ∆+=∆⇒ +=∆⇒= +−∆ = −∆ = −∆ = ∆ =−∆=∆ + 75.0,5.0,3,1, )1( , )1( )1( )1(0 1714 )1( 171417141714 1
  42. 42. Maximum Jet Impact Force [ ] [ ] ( ) ( ) [ ]80.0,66.0 2 1 )1( )2( 60.0,33.0,3,1, )2( , )2( 2 )2(2)2(20)2(2 0 )( )))2(2((009115.0 )(01823.0 )(01823.001823.0 1 22 1 22 ∈ + + = ∆ + ∆ + = ∆ ∆ ∆×∈∆∈∆ + =∆∆ + =∆ ∆+=∆⇒+=∆⇒=+−∆⇒ = −∆ +−∆ = −∆= −∆=∆=−∆=∆ + + + + m m P m m P m m P P PPmP m m PP m P PmPcQmPcQmQP cQQP cQmQPC dQ dF cQQPCF cQPQCPQCFcQPP t t HPb IFb tbtbtf ft m t m t m t m tdj m tdj m tdbdj m tb ρ ρ ρ ρρ
  43. 43. Ex1. Known Cleaning Needs ? psig3000Pr.... min/225. 91.0,1250 900min/247 2800min/485 /6.9 32/203 sticsCharacteriBitNext SurfAllowMax galQMin EfficiencyhpHP psigPgalQ psigPgalQ gallbmMW inNozzles LiftCutting Pump p p = = == =⇒= =⇒= = ×=
  44. 44. Ex1. Known Cleaning Needs ( ) ( ) psigPpsigP AC Q P bb td b 491 32 12 4 3 )95.0( 247)6.9(10311.8 ,1894 32 12 4 3 )95.0( 485)6.9(10311.810311.8 22 2 25 222 2 25 122 25 =               × =∆=               × =∆⇒ × =∆ −−− ππ ρ ( ) ( ) min/225 :)3( 1875)3000( 218.1 2 )1( 2 :)2( min/650 3000 )91.0)(1250(17141714 :)1( 18.1 247/485log 409/906log 40949190090618942800 min max max max 21 galQ Interval psigp m P Interval gal P EHP Q Interval m psigPpsigP PPP f P ff bpf = = + = + =∆ === == =−=∆=−=∆ ∆−∆=∆
  45. 45. Ex1. Known Cleaning Needs ( ) ( ) min/650 32/)15,14,14( 3.14 3 47.04 32 47.0 )1700()95.0( )650)(6.9(10311.8 10311.8 170013003000,1300min,/650 2 2 25 2 25 galQ D D in PC Q A psiPpsiPgalQ Opt Optbd Optt bfopt =⇒ =⇒ = × × ×= = × ⇒ ∆ × = =−=∆=∆= − − π ρ
  46. 46. Ex2. Known Cleaning Needs  Hole Size +Min. Ann. Vel.:  Drill String +Surf. Equip.:  Mud Program  Pump: 3423 Psi Max. Surf. Press. 1600 hp Maximum Input 0.85 Pump Efficiency Washed Out 9.857 in to 10.05 in ID Casing ID 10.05 in ID 120 ft/Min Minimum Annular Velocity Depth (ft) MW (lb/gal) PV (cp) YP (lb/100sq ft) 5000 9.5 15 5 6000 9.5 15 5 7000 9.5 15 5 8000 12.0 25 9 9000 12.0 30 12 4000 ft Casing Point 1000 ft Incremental interval 9000 ft End Point 3.826 in ID 4.5 in, 16.6 lb/ft Drill pipe 2.75 in ID 7.5 in, 600 ft Drill Collars Surf. Equip. 340 ft Drill Pipe
  47. 47. Ex2. Known Cleaning Needs ( ) ( ) ( ) ( ) ( ) ( ) ( ) psiPpsiP L d v PFlowTurb d N sft d Q vgalQ galQ Interval psip m P Interval gal P EHP Q Interval sdp p dpcr cr p y He Selected f P 38 4400 340 490,4906005000 825.31800 1595.135.9 1800 ,.4200Re 7200Re114650 15 825.3)5)(5.9(3710037100 /95.13 )826.3(448.2 500 448.2 min/500 min/395 60 120 5.405.10448.2 :)3( 1245)3423( 275.1 2 )1( 1 :)2( min/681 3423 )85.0)(1600(17141714 :)1( 25.1 25.075.175.0 25.1 25.075.175.0 2 2 2 2 22 22 min max max max ==∆=−=∆ ∆=∆⇒> =⇒=== ===⇒= =      −= = + = + =∆ === µρ µ ρτ
  48. 48. Ex2. Known Cleaning Needs Depth DPs DPdp DPdc DPdca DPdp DPf 5000 38 490 320 20 20 888 6000 38 601 320 20 25 1004 7000 38 713 320 20 29 1120 8000 51 1116 433 28 75 1703 9000 57 1407 482 27 111 2084 Depth (ft) Q (gal/min) DPf (psi) DPb (psi) At (sq in) Nozzle Size 5000 600 1245 2178 0.380 12,13,13 6000 570 1245 2178 0.361 12,13,13 7000 533 1245 2178 0.338 12,12,13 8000 420 1245 2178 0.299 11,12,12 9000 395 1370 2053 0.302 11,12,12 * inequality in nozzle size make a more suitable environment for rock failures
  49. 49. Surge press. of Ver. Pipe Move: ( ) ( ) ( ) ( )( ) ( )2 1 2 2 2 12 2 1 2 2 12 2 1 2 2 3 0 0 2 2 00 2 2 212 ),( 212 1 2 ,1 2 1 00 2 : 1500 )( rr v rrrr dL dp Q rrhrrWhA Whv dL dpWh dy h y Wvdyyyh dL dpW Q vWdyvdAQ h y vyyh dL dp v vhyvvy v y dL dpy vflowSlotBy d vv dL dp pf pfh h p f p f p f pif −−−−= −=−== −=      −−−= ==      −−−= =⇒=−=⇒= +−−= −− = ∫ ∫ π µ π π µµ µ µ τ µ µ
  50. 50. Surge press. of Ver. Pipe Move: ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( )2 1 2 2 2 12 4 2 12 2 1 4 2 1 2 2 222 1 22 12 2 1 2 2 2 1 2 12 2 1 2 12 )(46 )(43 , 15001000 2 4 , 4 1000 2 ddddd dddd vv ddvdvddv QQQ d vv dd v v dd vd dd Q v d vQ dd v v dL dp pa aip ait pi p a p ap p a f −−− −− =⇒        −+=− += + = −       + − = − == −       + = πππ µ µ π π µ
  51. 51. Ex. Surge press. of Ver. Pipe Move: ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) ( ) gallbm D p psip ftpsi dd v v dL dp sft dd vd v BottomClosedwith psipftpsi dL dp dd v v dL dp sftv BottomOpenedwith BottomCloseed BottomOpened EMW inIDCasinODCasinODHole cpgallbmMWftDepthsftRate f ef p a fp a f f p a f a a /11.9 4000052.0 23 0.9 052.0 2300584.04000 /00584.0 75.10121000 2 0.1 06.42 1000 2 ,/06.4 75.1012 75.10)0.1( : 04.400101.04000/00101.0 75.10121000 2 0.1 489.02 1000 2 ,/489.0 75.101275.10124106 75.101275.104103 )0.1( : ? 00.10.75.10.12 0.2/0.94000/1 22 12 22 2 2 1 2 2 2 1 2 2 12 2224 224 =+= ∆ +=⇒=×=∆⇒ = −       + = −       + == − = − = =×=∆⇒= −       + = −       + =+= −−− −− =       === ==== ρρ µ µ µ
  52. 52. Particle Slip Velocity (Newtonian): ( ) ( ) ( ) ( ) ( )         − = − = − == →> <= − = → −=⇒    −= = −=−=−=⇒    = = ↓ ↓ ↓ f fss sl f fs sl s slfs sfs k yEmpiricall sslfsfs sl Unit Field fs s sl sfs sls sfsSfsbo Sfbo Ss f d v v d vd d AE F f dvd v g d v dF vdFLawStokes dgVFWF gVF gVW ρ ρρ ρ ρρ ρπ πρρ µ ρ µ ρρ ρρ µπρρ µπ πρρρρ ρ ρ )( 89.1 )( 57.3 2 1 6/)( 1.0Re, 1.0 928 Re, 138 18 1 6/)( 3: 6/)()( 2 22 3 2 2 3 3
  53. 53. Particle Slip Velocity (Newtonian): ( )( ) ( ) ( )[ ] ( ) ( ) ( ) ( ) ( ) ftftD sftORsftv f d vff v d f dv sftv tcpgallbmMW Solidd sl f fss sl Graph f fs sl s sslf sl a Ss 5 4.01 01.0 303,4.0,3031.1030 /1.10/17.0 33.8 )33.833.86.2( 5 025.0 89.1 )( 89.1,5,40Re81.0,108.0,222Re 108.0 33.815.1 33.833.86.2025.057.3)( 57.3 1.0222 928 Re,/15.1 1 025.033.8)33.8(6.2138 min301/33.8 %1%6.281.0025.0 22 2 = − === =      − =         − === →=== = − = − = >=== − = === ==== φ ρ ρρ ψ ρ ρρ µ ρ µ ρψ
  54. 54. Particle Slip Velocity (Non-Newtonian): ( ) ( ) )(4.10 ),(4.10 )( 66 )( . 2 3 fs g Maxsfssg Unit Field fs s ggs s fs dd d d d F ρρ τ ρρτ ρρττπ π ρρ − =−= → −=⇒=      −=↓
  55. 55. (William C. Lyons - Air and Gas Drilling Manual) AIR AND GAS DRILLING
  56. 56. Basic Technology Introduction Surface Equipment Down hole Equipment Compressors ShallowWell DrillingApplications
  57. 57. Introduction  Air and gas drilling technology is the utilization of compressed air or other gases as a rotary drilling circulating fluid to carry the rock cuttings to the surface.  The compressed air or other gas can be used by itself, or can be injected into the well with incompressible fluids such as fresh water. three distinct operational applications 1. Air or gas drilling operations. (using only the compressed air or other gas as the circulating fluid). 2. Aerated drilling operations. (using compressed air or other gas mixed with an incompressible fluid). 3. Stable foam drilling operations. (using the compressed air or other gas with an incompressible fluid to create a continuous foam circulating fluid).
  58. 58. Circulation Systems Direct Circulation: Reverse Circulation:
  59. 59. Reverse Circulation The reverse circulation technique is useful for drilling relatively shallow large diameter boreholes. At the bottom of the borehole the drilling mud entrains the rock bit cuttings and flows through the large orifice in the drill bit. Dual tube closed reverse circulation system is a specialized type of reverse circulation and is usually limited to small single and double drilling rigs with top head rotary drives. Note: actual objection of this method is eliminating of the nozzle effects.
  60. 60. Comparison of Mud and Air Drilling
  61. 61. Flow Characteristics AN EXAMPLE Depth From: 7000 ft Drill bit Diam.: 7 7/8” D.P: 9500 ft, OD: 4 1/2” CSG Diameter: 8 5/8” D.C: 500 ft D.P: 16.6 lb/ft, S135 Casing weight: 28 lb/ft D.C: OD: 6 ¾”, ID: 2 13/16” Nozzle Size: 3 x 13/32”
  62. 62. Flow Characteristics (PRESS.) MW: 10 lb/gal YP:10 lb/100 sq. ft : PV: 30 cp Flow Rate (GPM): 300 LIQUID BASE MUD V.S. AIR BASE MUD AW: 1.35 lb/Cu.Ft YP: 0 :PV: VARIABLE cp Flow Rate: 2x1,200 SCFM
  63. 63. Flow Characteristics (HEAT CAP.) HEAT CAPACITY OF LIQ=CL HEAT CAPACITY OF GAS=CG LIQUID BASE MUD V.S. AIR BASE MUD CL >> CG
  64. 64. Flow Characteristics (DEN.) LIQUID BASE MUD V.S. AIR BASE MUD DEN.L= CTE. DEN.G= VAR.
  65. 65. Flow Characteristics
  66. 66. Drilling Location
  67. 67. Air Drilling Location & Acc.  Nearly all air and gas drilling operations are land operations.  Normally a rig is a typical mud rotary drilling rig that has been set up to drill with compressed air as the circulating fluid.  The primary compressors (low pressure) supply compressed air to a flow line between the compressors and the rig standpipe.  There are 2 to 4 primary compressors supplying the rig.  These compressors intake air from the atmosphere and compress the air in several stages of mechanical compression.  These are positive displacement fluid flow machines, reciprocating piston, or rotary compressors.  Compressors are capable of an intake rate of about 1,200 acfm of atmospheric air and output air at pressures up to approximately 300 psig.
  68. 68. Air Drilling Location & Acc.  booster compressor is a reciprocating piston compressor.  booster compressor is used to increase the flow pressure from the primary compressors to pressures up to approximately 1,000 psig.  In most drilling operations the pressure is less than 300 psig therefore, the booster is used for special operations such as directional drilling.  Downstream from the booster are liquid pump systems that allow water with solids to be injected into the compressed air flow to the rig.  The blooey line runs from the top of the annulus to the burn pit and allows the air with the cuttings to exit the circulating system to the atmosphere.  For oil and natural gas drilling operations, a pilot flame is placed at the exit of the blooey line.  The mud tanks are maintained at air and gas drilling operation locations in the event high bottomhole pressure forces conversion to mud drilling.  A drilling location must be oriented so that the blooey line exit is downwind of the prevailing wind over the site.
  69. 69. Flow Line to the Rig Bleed-Off Line: The bleed-off line allows pressure to be released throughout the flow line to the rig and inside the standpipe, rotary hose, kelly, and the drill pipe to the depth of the first float valve. Scrubber: The scrubber removes excess water in the compressed air flow in the flow line. Water is collected in the bottom of the surge tank as the air flows through this tank and is vented to eliminate the water from the line. Solids Injector: It is used to inject hole drying and hole stabilizing powders into the well to dry water seeping into the well from water-bearing rock formations. Water Injection Pump: Unstable foam (mist) require the injection of water into the air before the air is injected. It injects water, chemical corrosion inhibitors, and liq. foamers into the comp. air flow line. Gauges: Each compressor has gauges to assess its performance. low pressure gauge is placed down-stream of the compressors but upstream of the booster. Valves & check valves: manually and remotely valves are located along the flow line to the rig. These valves are gate or ball type & can’t be operated in a partially open position. Check valve is one way valve to prevent reverse flow.
  70. 70. Volumetric Flow-Rate Meters  Volumetric flow rate of air is referenced to the atmospheric conditions of the air entering the primary compressor.  At sea level flow rate is given as standard cubic feet per minute (scfm).  At locations above sea level flow rate is given as actual cfm (acfm).  There are two techniques for determining the air flow rate: Orifice plate: Gas turbine flow meter: • Orifice plate with a differential pressure gauge to measure the difference between the pressure upstream and downstream of the plate.
  71. 71. Wellhead Equipment  All air and gas drilling operations require the use of a rotating head which is installed below the rotary table.  BOP stack is always used when subsurface over pressured dangerous gases or fluids might be encountered while drilling.  G denotes a rotating head  A denotes an annular BOP  S denotes the drilling spool  R denotes pipe or blind rams  Low pressure rotating head
  72. 72. ROTATING HEAD  This Figure shows an exploded view of the four major sections of the rotating head.  The top three sections are the internal sections of the head and are easily removed in the field from the fourth section (the bowl or main housing and quick-lock clamp assembly).  The top section is the Kelly driver with lugs on its side that lock into the bearing assembly shown below it.  The bearing assembly allows the inside of this assembly to rotate with the drill string and its outside to seal inside the non-rotating housing  stripper rubber is attached to the bottom of the bearing assembly that is designed to fit and rotate with the Kelly.  Any air or gas pressure in the annulus acts to fit more tightly around the kelly and drill string.
  73. 73. ROTATING HEAD  In order to place the drill string and Kelly into the well, the quick-lock clamp must be unlocked and the three rotating internal sections lifted to the rig floor.  The drill bit with the drill collars are placed in the well through the open rotating head.  The internal sections of the rotating head are fitted over the bottom tool joint of the drill pipe.  If a well will be making large volumes of natural gas, the bottomhole assembly of the drill string is designed to allow the stripper rubber to be stripped over the collars to the bit.  The stripper rubber diverts the air or gas with rock cuttings to the outlet (to the blooey line).  Higher pressure heads are capable of pressures up to 1,500 psig (with 100 rpm), up to 3,000 psig (in stationary). Cut view of a rotating head with dual stripper rubbers
  74. 74. Blowout Prevention Stack (BOP)  BOP equipment (or the BOP stack) were developed to provide protection of surface from high pressured deposits.  The first line of defense against the dangers of high pressure deposits is weighted drilling mud.  When too light a drilling mud is used and a high pressure deposit is drilled, the well will receive a liquid or gas “kick.”  If the kick is mostly natural gas, the gas will expand as it moves up the drill string annulus to the surface.  The surface wellhead equipment is the second line of defense against a blowout.  This BOP stack must contain this gas pressure while the slug is circulated under control to the surface and expelled from the annulus via a flow line to a remote burn area where the slug can be safely burned off.  Rams of BOP can be actuated manually or hydraulically.
  75. 75. types Blowout Prevention Stack the ram-type blowout preventer: Blind ram is capable of sealing the well completely by compressing the drill pipe in a manner to prevent the well fluids from escaping to the surface. Pipe ram has a geometric shape on the end of rams that conform to the outside surface of the drill pipe therefore, drilling mud can be circulated down the inside of the drill pipe. the annular-type preventer: Hydraulic forces the operating piston upward against a pusher plate that in turn displaces (compresses) an elastomer donut inward to seal on the outer surface of drill pipe, drill collar, casing. when annular BOP is closed, by decreasing hydraulic force drill string can be moved up & down partially in order to preventing pipe stuck.
  76. 76. Flow Line from Rig  Drilling operations using compressed air & gases require the use of large diameter flow lines.These return flow lines should be designed not to choke the gas flow as it exits the circulating system.  This line is known as the “blooey line” which derives its name from the sound made when a slug of water is ejected from the line with high velocity air or gas.  Blooey Line: Blooey lines are required for all air and gas drilling and are needed to keep cuttings away from the drilling rig and personnel.  The blooey line should be designed with a inside cross-sectional area greater (by a factor of 1.1) than the annulus cross-sectional area at the top of the well.  This is not practical when drilling a shallow larger diameter borehole sections.  All blooey lines are equipped with two high pressure gate valves that are located on the horizontal blooey line at its entrance .
  77. 77. Burn Pit  The burn pit should always be located away from the standard mud drilling reserve pit (water storage for an emergency mud drilling operation).  The burn pit is located downwind from the drilling rig to keep the smoke and any dust from the drilling operation from blowing back over the drilling rig.  The burn pit must be lined with an impermeable layer of commercial clay to prevent contamination of surrounding soil and ground water.  Burn pit is designed with a high berm (6 ft) at one side of the pit that prevents high velocity rock particles and liquid slugs from passing over the burn pit.
  78. 78. Primary and Secondary Jets  This figure shows the high pressure vent lines from the compressor for the primary and secondary jet flow lines.  These jet flow line in the blooey line are only required for drillings directed toward the recovery of oil, gas products.  Primary and secondary jets are incorporated into the blooey line to allow the safe venting of the top of the wellhead when the well is producing natural gas or other dangerous gas. • These lines allow for the direct discharge of air from the compressors into the blooey line. This discharge into the closed blooey provides jet pumping action which forces any gas venting from an atmosphere exposed wellhead to flow to the blooey line and exit this line at the burn pit.
  79. 79. Flow Line from Rig Sample Catcher allows samples to be obtained from a well during the drilling that is installed in the body & near the entrance of the blooey line. Gas Detector is used only in air drilling directed at the recovery of oil and gas that can detect small quantities of hydrocarbon that might enter the blooey line from the annulus. De-Duster is located near the exit end of the blooey line. The de-duster is a small Diam. pipe water sys. located inside the blooey line. A pump supplies with water that is sprayed on the dry rock dust particles that exit the line. This reduces or the dust clouds that are typical of air & gas drilling. Pilot Light is used only in air or gas drilling directed at the recovery of oil and natural gas. The pilot maintained at the end of the blooey line to burn any hydrocarbons that might exit the line as the drilling progresses.
  80. 80. Downhole Equipment  Larger diameter shallow and intermediate depth wells are usually drilled with reverse circulation techniques.  These techniques and their associated equipment are virtually unknown to those who drill deep small diameter wells.  In this section mentioned parts will be explained:  Rotary Drill String  There are two general types of drill strings used in air and gas drilling: 1. The standard drill string discussed below is used almost exclusively for deep direct circulation operations. 2. The dual wall pipe drill string is used exclusively for intermediate and shallow depth reverse circulation operations.
  81. 81. Standard Drill String  Such a drill string would be used on large drilling rigs.  The drill bit is threaded to a bit sub.The bit sub is a short thick wall pipe that has a female thread or threaded box on both ends.  Above the bit sub are the drill collars.  The bit sub is used to protect the bottom threads of the drill collar from the wear caused by the frequent bit changes.  A drill collar is a thick wall pipe that provides the weight on bit.  Because of differences in connections a special crossover sub must be used to mate the drill collars to the drill pipe.  Only the drill collars can be placed in compression.
  82. 82. Dual Wall Pipe Drill String  Intermediate depth large diameter wells can be drilled with direct circulation. But reverse circulation techniques are more efficient techniques.  Reverse circulation techniques are not restricted to air drilling. Reverse circulation techniques often use standard drill string.  It must be used on drilling rigs equipped with hydraulic power swivel systems to rotate the drill string.  Dual wall pipe is rigid and has a higher weight per unit length than standard drill pipe.Thus, it can be used like drill collars.  At bottom hole the air flow entrains cuttings and flows to the surface through a large center orifice in the drill bit.  Side inlet sub (first swivel) allows air to be injected into the dual wall pipe annulus through the non-rotating outer section.The return flow of air and cuttings from the inside pipe flows up through the rotating inner section of the sub.
  83. 83. Drill Bits  drag bits:  have fixed cutter blades that are integral with the body of the bit & have no moving parts.  PDC bits have specially designed diamond cutter elements bonded to small tungsten carbide studs.  Their cutting mechanism is a scrapping action that is best used to drill formations that fail in a plastic mode. (e.g., soft, firm and medium-hard, non-abrasive rock formations).  drag bits require incompressible liquid fluids to keep the diamonds from being damaged by excessive heat.  Thus, these modern drag bits have very limited applications in air and gas drilling.
  84. 84. Roller Cutter Bits  Roller cutter bits use a crushing to remove rock from the cutting face.The weight or axial force that is applied to the bit is transferred to the teeth on the bit.  Force applied is sufficient to fail the rock in shear & tension & cause particles of the rock to separate from the cutting face.  When this crushing takes place well filled with drilling mud, the hydrostatic pressure compresses the rock face.  Compression makes the crushing be less efficient & ultimately reduces the overall drilling rate of the bit (for a givenWOB).
  85. 85. Roller Cutter Bits (Air Drilling)  In air drilling this crushing takes place at the bottom of a well filled only with air, there is little hydrostatic pressure on the rock face.  The in-situ pre-existing stresses in this block of rock prior to the drilling & the vertical cylindrical void of the new borehole create a thin tension stress field in the rock material just below the rock face.  This makes the crushing action very efficient and increases the overall drilling rate of the drill bit (for a givenWOB).
  86. 86. Tri-Cone Bits  The offset is the degree the cones of the bit are designed to depart from a true rolling action on the rock face.  Most air or natural gas drilling operations use insert tri-cone drill bits.  These tri-cone drill bits are designed with special internal air passages to provide the bit bearings with the appropriate cooling from the less dense air or gas.  This large orifice allows the return flow of drilling fluid and cuttings to flow from the annulus through the large orifice in the bit body to the inside of the drill string.  Tri-cone drill bits used for air and gas drilling are usually designed with increased gauge protection.
  87. 87. Single Cone Bits  the single cone bits drill by a scraping action.Thus, the single cone drill bits utilize wear resistant tungsten carbide inserts in the cutting structure.  These drill bits are most effective in smaller diameters & they are suitable for drilling soft as well as medium and hard rock formations.  It is standard to use single cone drill bits with open orifices in air & gas drilling.
  88. 88. classification system in three-digit code The first digit is the rock formation series number.  The letter “D” precedes if the bit is diamond or PDC drag type bit.  The first digit 1 to 3 are reserved for milled tooth bits in soft, medium, and hard formation categories.  The first digit 5 to 8 are for insert bits in soft, medium, hard and extremely hard formation categories. The second digit is called the type number.  Type 0 is for PDC drag bits.  Types 1 to 4 designate a formation hardness sub-classification from the softest to the hardest formations with each series category. The third digit is the feature number.  For diamond and PDC drag bits the features numbers are 1 to 8 and refer respectively to: step type, long taper, short taper, nontaper, downhole motor, side-track, oil base, and core ejector.  For roller cutter bits are 1 to 7 and refer respectively to: standard roller bearings, standard roller bearing for air applications, standard roller bearing with gauge protection, sealed roller bearings, sealed roller bearing with gauge protection, sealed journal bearing, and sealed journal bearing with gauge protection.
  89. 89. Bottomhole Assembly  This section of the drill string determines how much weight can be placed on the bit and how “straight” a vertical borehole will be drilled with the drill string.  The addition of stabilizers to the drill collar string generally improves the straight drilling capability of the drill string.  Air drilled boreholes have more deviation than a mud drilled boreholes because of the fact that air drilling ROPs are higher than a mud drilling.  To correct this a more stabilized BHA when drilling an air drilled borehole than would be used.  Drill collars are thick walled tubular that are used at the bottom of the drill string.  Their purpose in the drill string is to provide the axial force needed to advance the drill bit. When drilling a vertical borehole, the axial force is the weight of the drill collars.  Drill collars are available in ~30 ft long.
  90. 90. Stabilizers & Reamers  Stabilizers and reamers are special thick walled drill collar subs that are placed in the BHA to force the drill collars to rotate at the center of the borehole.  There are 2 types of stabilizers:  Integral blades are machined into (integral) the stabilizer body, or are rigidly attached to the stabilizer body.  Sleeve type blade has a sleeve with the attached metal blades (sleeve rotates) and can be replaced on the stabilizer body when the blades wear.  Care must be exercised in using stabilizers in air drilling.The wear rate on stabilizer blades in air drilling operations will be greater than in a mud drilling.  The rolling cutter reamer is a special type of stabilizer tool that provides “blades” that are cylindrical roller cutters that can crush and remove rock from the borehole wall.
  91. 91. Heavy-Weight Drill Pipe  Heavy-weight drill pipe is an intermediate weight per unit length drill string element.  The characteristic of this type of drill pipe is that it can be run in compression in the same manner as drill collars.  One feature of heavy-weight drill pipe is the wear pad in the center of the element that acts as a stabilizer  That improves the stiffness of the heavy-weight thus reduces the deviation of boreholes.  heavy-weight drill pipe above the drill collars, and standard drill pipe above the heavy-weight drill pipe.  Heavyweight drill pipe is used in directional drilling. Using heavy-weight drill pipe in place of drill collars reduces the rotary torque and drag, and increases directional control.
  92. 92. Dual Wall Pipe  This type of drill pipe is used for drilling shallow wells (~ 3,000 ft or less).  These rotary drilling operations are carried out with hydraulic top drives (for single rotary drilling rigs) and with power swivels (for triple rotary drilling rigs).  This type of dual wall pipe has an inner-tube that is O-ring slip fitted into a similar inner-tube in the next element of drill pipe when elements are made up to each other.
  93. 93. 1) adapter sub 15) O-rings 2) air swivel 16) interchange sub 3) O-ring 17) Standard down-the- hole air hammer 4) air swivel inlet 18) connector tube for reverse circulation downhole air hammer 5) O-rings 19) O-rings 6) shaft adapter 20) reverse circulation downhole air hammer 7) O-rings 21) O-rings 8) Saver sub adapter 22) Bit connector sleeve 9) O-rings 23) rock bit sub 10) center tube 24) wear sleeve 11) saver sub 25) tri-cone bit 12) O-rings 26) open face drag bit for coring 13) dual wall drillpipe 27) latching bit sub 14) interchange connector tube
  94. 94. Safety Equipment  FloatValves This is a safety valve device and is usually placed in the bit sub at the bottom of the drill string.  It prevents the back flow of gas and cuttings from entering the annulus space into the inside of the drill string & is fitted with a flapper mechanism.  Fire float valves and fire stop valves are used only for oil and natural gas recovery drilling operations & are placed just above the drill bit and along the drill string at several positions.  This valve is usually installed in the bit sub. In normal operation, air flow pressure from circulation forces a spring-loaded piston down allowing the air to circulate.  When design temperature is exceeded, a zinc ring melts which in turn allows a sleeve to close over air ports stopping circulation and the supply of air to the bottom of the borehole.
  95. 95. Kelly Sub Valves  At the top of the drill string (just above the Kelly) is a Kelly cock sub which is fitted with a ball valve.  In the event of a subsurface blowout, the Kelly cock’s ball valve can be closed and the sub left made up to the top of the Kelly.
  96. 96. Drill String Design  One of the initial planning steps for a rotary drilling is the design of the drill string.  The drill string must have the strength to drill to the intended target depth  The drill string must be light enough so that the hoisting system can extract the string from the well when the target depth has been reached.  The axial tension force , F (lb), at the top of the drill string in a vertical well is:
  97. 97. Drill String Design  The maximum allowable design axial tension force, Fa (lb), is:  where Fy is the drill pipe tension force to produce material (steel) yield (lb).  For most drill string designs a factor of safety is used to insure there is a margin-of-over pull (MOP) to allow for a stuck drill string.  The drill string design factor of safety, FS, is given by:  The MOP is determined by the rotary drilling rig hoisting capacity.Thus, MOP is:  where Fc is the hoisting capacity of the rotary drill rig (lb). But the total hoisting axial force cannot exceed Fa.
  98. 98. Ex. Drill String Design  Rotary air drilled from 7,000 ft to 10,000 ft  Three cone drill bit size = 7 7/8”  direct circulation drilling operation  The drill pipe isAPI 4 1/2 inch, 16.60 lb/ft.  BHA: 500 ft of 6 3/4 inch by 2 13/16 inch drill collars and similar diameter survey subs and nonmagnetic drill collars.  Determine the FS and the MOP?  100 lb/ft for the 6 3/4 inch by 2 13/16 inch drill collar.  18.62 lb/ft for the drill pipe.  drilling fluid is air then m = 0, and Kb = 1.0.γ  The maximum axial tension force in the top drill pipe is @10,000 ft  F={(9500)(18.62)+(500)(100)}(1) = 226890 lb  yield in the drill pipe = 595,004 lb.  FS=(0.9)(595004)/(226890) = 2.36  maximum hoisting capacity of rig is 300,000 lb  MOP=300,000−226,890 = 73,110 lb
  99. 99. Typical application ranges of compressor types • Positive displacement compressors are best for high pressure (~200 psi) & moderate volumetric flow rate magnitudes (103 acfm). • Dynamic compressors are best for large volumetric flow rates (1,000,000 acfm) & with only moderate pressure ratios (~20 psi).
  100. 100. General performance curves for various compressor types  Thus, positive displacement compressors are normally applied to industrial operations where volumetric flow rates are critical and pressure ratios are variable.  Dynamic compressors are generally applied to industrial operations where the volumetric flow rate and pressure ratio requirements are relatively constant.
  101. 101. Continuous Flow (Dynamic) Compressors Centrifugal Compressors:  The compression of the gas results from the speed of the flow through a specified geometry within the compressor. It uses centrifugal forces on the gas created by high velocity flow of the gas in the cylindrical housing.  The gas to be compressed flows into the center of the rotating impeller.The impeller throws the gas out to the periphery by means of its radial blades rotating at high speed.  The gas is then guided through the diffuser where the high velocity gas is slowed which results in a higher pressure in the gas.
  102. 102. Continuous Flow (Dynamic) Compressors Axial-Flow Compressors:  Axial-flow compressors are very high-speed, large volumetric flow rate machines.  This type of compressor flows gas into the intake ports and propels the gas axially through the compression space via a series of radial arranged rotating rotor blades and stationary stators (or diffuser) blades.  As in the centrifugal compressor, the kinetic energy of the high-velocity flow exiting each rotor stage is converted to pressure energy in the follow-on stator (diffuser) stage.
  103. 103. Positive Displacement Compressors  In general, the reciprocating compressor allows for rather complete reliable flexibility in applications requiring variable volumetric flow rates and variable pressure ratios.The rotary compressor does not allow for much variation in either. Reciprocating Compressors:  Reciprocating compressors are available in both lubricated and non-lubricated versions.  The lubricated versions provide lubrication for the moving pistons. In some cases where oil must be omitted from the air there are rings and wear bands around of each piston.  They have inlet & outlet valves that actuated by pressure differential & called self-acting valves. Single-acting Compressors
  104. 104. Positive Displacement Compressors  The main advantage of these compressors is their extremely high pressure output capability and reliable volumetric flow rates.  The main disadvantage of these compressors is that they can not be practically constructed in machines capable of volumetric flow rates much beyond 1,000 actual cfm.  In multistage compressors with nearly equal compression ratios the volumetric flow rate is reduced from one stage to the next. Double-acting Compressors
  105. 105. Positive Displacement Compressors Rotary Compressors:  They have no valves & being light weight that can handle flow rates up to 2,000 acfm & pressure ratios up to 15.  The most rotary compressors are the sliding vane, helical lobe (screw), and liquid piston.  The upper Figure shows the situation when the back pressure on the outlet side is equal to the built-in design output pressure & there is no expansion of the output gas as it exits.  The middle Figure shows the situation when the back pressure on the outlet side is above the built-in design output pressure & compressor cannot expel the gas volume within it efficiently so the fixed flow rate will be reduced from the volumetric flow rate .  The lower Figure shows the situation when the back-pressure on the outlet side is less than the built-in design output pressure & the gas exiting expands in the expansion tank & the initial portion of the pipeline until the pressure is equal to the pipeline back pressure.
  106. 106. Rotary Compressors SlidingVane Compressors:  The type is a rotating cylinder located eccentric to the center-line of a cylindrical housing.  Gas is brought into the compression stage through the inlet suction port.The gas is then trapped between the vanes, and as the inside cylinder rotates the gas is compressed to a smaller volume as the clearance is reduced.  The volumetric flow rate for a sliding vane compression stage, qs, is approximately: qs = 2 a l (d2 - m t) N  a = (d2 - d1)/2 •qs is volumetric flow rate (cfm), •a is the eccentricity (ft), •l is the length of the cylinder (ft), •d1 is the outer diameter of the rotary cylinder (ft), •d2 is the inside diameter of the cylindrical housing (ft), •t is the vane thickness (ft), •m is the number of vanes, •N is the speed of the rotating cylinder (rpm). i.e. d1/d2 = 0.88, a = 0.06 d2 and l/d2 = 2.00 to 3.00. typical vane tip speed usually should not exceed 50 ft/sec.
  107. 107. Rotary Compressors Helical Lobe Compressors:  This type is made up of two rotating helical shaped shafts, or screws. One is a female rotor & the other a male rotor that turn counter to one another.  Like all rotary compressors, there are no valves.The gas flows into the inlet port & is squeezed between the male & female portion of the rotating intermeshing screw elements and the housing. Liquid Piston Compressors:  It utilizes a liquid ring as a piston to perform gas compression within the compression space.  The liquid piston compressor stage uses a single rotating element that is located eccentric to the center of the housing.  As rotation takes place, the liquid forms a ring as centrifugal forces & the vane force the liquid to the outer boundary of the housing.  main advantage to this type of compressor is that it can be used to compress gases with significant liquid content in the stream.
  108. 108. Compressor Shaft Power Requirements  The most important single factor affecting the successful outcome of air and gas drilling operations is the availability of constant, reliable volumetric flow rates of air or gas to the well.  The only two compressor subclasses that can meet these flexibility requirements are the reciprocating compressor & the rotary compressor. Basic Single-Stage Shaft Power Requirement:  is the work ideally required for effecting the actual compression within the compressor.Thus, the net area abcd measures the net shaft work for the induction, compression & delivery of the gas under conditions which are assumed to be ideal.  The total shaft work,Ws (ft-lb/lb), required for compression can be written as: •Ws is the total shaft work (ft-lb/lb), •V1 is the velocity of the gas entering the compressor (ft/sec), •V2 is the velocity of the gas exiting the compressor (ft/sec), •g is the acceleration of gravity (32.2 ft/sec2). * Assuming a poly-tropic process, where P1V1^n=P2V2^n= P x V ^n= cte, n = constant, and the simplest poly-tropic process where the exponent term n ≈ k, where k is the ratio of specific heats for the gas involved in the process (e.g., for air, k = 1.4) a  b  c  d
  109. 109. Compressor Shaft Power Requirements ( )            −      − =−=×           −      − =→ − − +           −      − = − +      − − =       − − =− =      →×=×→    = =         −      − =−⇒=−=− − ••• − − − −− − ∫ ∫∫∫ 1 1 sec)/(sec)//()( 1 1 )( 2 2 1 12 1 1 1 1 1 1 & 1 1 2 sec)/( 11 3 1 1 2 1 2 1 2 2 2 1 2 2 1 1 2 1 2 1 2 2 2 1 1 2 11 2 1 2 1 1 1 21 22 1 11 111 2211 1 2 11 2 1 111 2 1 11 2 1 3 k k ftQ sS k k S k k S k k kk kk k k k P P vwP k k lbftWftlbwftW P P RT k k ftWsmallsois g vv g vv P P RT k k g vv T T RT k k W T T k RT Pdv T T P P vRTvRT RTvP vPvP v v k RT PdvRTvP v dv vPPdv
  110. 110. Multistage Shaft Power Requirements  Above figure shows an example schematic of a two stage compressor with an intercooler between the compression stages. Because of intercooler the temperature of the gas entering stage 2 (at position 3) is the same as the temperature entering stage.  where pi is input pressure (psia),  po is output pressure (psia),  qi is the input volumetric flow rate (ft3/min). s s n i o s kn k iis s P P rrationCompressio P Pqp k kn HPW 1 1 1 2 1 17.2291 )(       ==           −      − = − •
  111. 111. Prime Mover Input Power Requirements  In order to obtain the complete picture of compressors, it is necessary to ascertain the prime mover input power requirement to operate the compressor shaft and the actual power available from the prime mover.  The application of the above equations will be slightly different depending upon whether reciprocation piston compressors or rotary compressors are being analyzed.  The actual power available from a prime mover is a function of elevation above sea level, and whether the prime mover is naturally aspirated or turbocharged.
  112. 112. Prime Mover Input Power Requirements  Primary Compressor System Unit: • Primary compressor system units take air directly from the atmosphere. • These compressor systems can be rotary or reciprocating compressors. • The compressors in these units can be single stage, or multistage. • These units can be fabricated as skid mounted, semi-trailer mounted, or as wheeled trailers.  Booster Compressor System Unit: • Operated downstream from a primary compressor system . • Feed from the primary compressor system and compress the air to a higher pressure. • These are all reciprocating compressors. • They can be single stage, or multistage • can be fabricated as skid mounted, semi-trailer mounted, or as wheeled trailers.
  113. 113. Reciprocating Compressor Unit  A reciprocating compressor adjust its output pressure to match the backpressure.Thus, can be more flexible than the rotary compressor and uses less fuel for a given application.  The intake flow rate of a real reciprocating compressor is smaller than the theoretical sweep volume.  where c is the clearance volume ratio for the compressor model. 0.06 < c < 0.12.               −−= 11 1 k sv rcε [ ] .99.0,84.0 frictoduem =ε
  114. 114. Reciprocating Compressor Unit  A three-stage reciprocating primary air compressor system unit.  With flow rate of 900 scfm and a max. press. capability of 240 psig at standard conditions.  maximum HP of 300 at a compressor shaft speed of 1,000 rpm at standard conditions.  clearance ratio of 0.06 and a mechanical efficiency of 0.90.  HP @ sea level & @ 6000 ft above sea level for back pressure of 150 psig? a) Surface location at sea level: hp W HPW HPW scfmq sokairfor r psiappsiapn mv s as s i v s ois 3004.190 9.0915.0 8.156 )( 156.81 7.14 7.164 17.229 9007.14 4.0 4.13 )( 900 915.01238.206.0196.0 :4.1 238.2 7.14 7.164 7.1641507.147.143 4.13 4.0 4.1 1 3 1 ≤= × = × = =           −            ×       × =⇒ = =           −−= = =      = =+=== • • ו εε ε
  115. 115. Reciprocating Compressor Unit b) Surface location at 6,000 ft above sea level: ( ) hpW hpW elevationofeffect W HPW HPW acfmq sokairfor r psiappsiapn as s mv s as s i v s ois 2342.168 23422.01300 : 2.168 9.0915.0 8.137 )( 137.81 8.11 8.161 17.229 9008.11 4.0 4.13 )( 900 910.01393.206.0196.0 :4.1 393.2 8.11 8.161 8.1611508.118.113 4.13 4.0 4.1 1 3 1 ≤= =−= = × = × = =           −            ×       × =⇒ = =           −−= = =      = =+=== • • • • ו εε ε
  116. 116. Shallow Well Drilling Planning  Shallow air and gas drilling use exclusively compressed air as the drilling fluid.  Some drilling have used oxygen stripped atmospheric air as the drilling gas. The basic planning steps for a shallow well are as follows: - Determine the geometry of the borehole section to be drilled with air or gases - Determine the geometry of the strings for the sections to be drilled with air or gas - Determine the rock type to be drilled and estimate the anticipated ROP. - Determine the elevation of the drilling site above sea level & Temp. Gradient - Determine whether direct or reverse circulation will be used. - Determine the minimum flow rate of air or gas needed to carry the cuttings. - Select compressor to provide flow rate greater than the required minimum flow rate. - Determine the bottomhole and surface injection pressure as a function of depth. - Determine the max power for compressors & the max power from the prime movers. - Determine the approximate volume of fuel for the compressor(s) to drill the well. - Determine the “mist” flow rate & water carrying capacity In the event formation water.
  117. 117. Direct Circulation  Direct circulation is extensively used in shallow air drilling operations.  In general, direct circulation is used to drill small diameter borehole wells.  Reverse circulation is preferred for large diameter borehole wells.  MinimumVolumetric Flow Rates:  The minimum volumetric flow rate values are calculated assuming a minimum bottomhole kinetic energy per unit volume of no less than 3.0 ft-lb/ft3  The calculations for determining a minimum flow rate is a trial & error process.  Average specific gravity for sedimentary rock is assumed to be 2.7
  118. 118. Illustrative Example  The minimum flow rate for a well with a 4 ½” OH & a DP’s OD of 2 3/8”.The anticipated ROP in a competent limestone rock is assumed to be 30 ft/hr,The drilling depth is 1000 ft.  Pat = 14.696 psia= 2,116 lb/ft2 abs Tg=Tat=519.67R  it is necessary to select (by trial and error) a qg, that will give a kinetic density of 3.0 ft-lb/ft3 in the annulus at the bottom of the 1,000 ft borehole.  Kinetic energy per unit volume should be a minimum at the bottom of the annulus.The volumetric flow rate selected (trial and error) is qg= 320.9 Scfm Qg=320.9/60 = 5.35 ft3/sec w˙g = γg x Qg = 0.408 lb/sec Dh = 0.375ft
  119. 119. Illustrative Example  = = 0.155 lb/sec  Tbh =Tr +0.01(1,000) = 59 + 10 =69 R Tav = 523.67R Dp = 0.198ft  ep is given as 0.00015 ft eoh is 0.005 ft eav=? = 0.0039ft = 0.051 aa = 0.026 ba = 331.6 Pbh = 3,792 lb/ft2 abs = 26.3 psia γ bh = (3792 x 1.0)/(53.36 x 528.67) = 0.136 lb/ft3 Qbh = (0.0763 x 5.35)/(0.136) = 3.007 ft3/sec  Vbh = 37.7 ft/sec ρbh = 0.136/32.2 = 0.00422 (lb-sec2)/ft4 KEbh = 0.5 x (0.00422) x (37.7)^2 = 3.002
  120. 120. Illustrative Example Minimum flow rate of air at standard conditions for 2 3/8” drill pipe and 4 ½” open borehole. Minimum flow rate of air at standard conditions for 2 3/8” drill pipe and 4 ¾” open borehole.
  121. 121. Illustrative Example 2  minimum volumetric flow rate of air required to drill a 4 ¾” OH with a drill string composed of 120 ft of 3 ½” by1 ½” DC above the bit and API 2 3/8”, 4.85 lb/ft.  Desired ROP is 30 ft/hr and the maximum depth is 1,200 ft.The formations is metamorphic rock.  Depth of 1,200 ft for an adjusted ROP of 33.3 ft/hr is approximately 378 scfm.  This is for sea level data so it must be modified to drilling location:  Pat = 11.769 psia = 1,695 lb/ft2 abs Tat =70+459.67= 529.67 R  γg = (1659 x 1)/(529.67 x 53.36) = 0.0600 lb/ft3  Actual conditions at the drilling location can be determined by equating the weight rate of flow of the air at the two conditions.This reduces to:  qg = 378(0.0763/0.0600) = 481 acfm RTE=6000 ft T=70 F ρG=3 Ka=30(3.0/2.7)=33.3 ft/hr
  122. 122. Injection Pressure and the Selection of Compressor Equipment a) The required flow rate & the compressor volumetric flow rate capability. b) The injection press. with required flow rate & the press. capability of the compressor. c) The horsepower required by the compressor & the input capability of the prime mover.
  123. 123. SULLAIR Model 840 Rotary Screw Compressor  The on-board primary compressor is a Sullair Model 840, two-stage, oil flooded, rotary helical lobe (screw) type.  This compressor is powered by a Caterpillar Model 3406, diesel fuel, turbocharged prime mover capable of a 400 peak horsepower at the operating speed of 1,800 rpm.  The compressor is capable of producing a volumetric flow rate of 840 scfm and a fixed pressure of 340 psig at API standard conditions. SULLAIR MODEL 840 A CATERPILLAR MODEL 3406
  124. 124. SULLAIR Model 840 Rotary Screw Compressor pat = 11.769 psia = 1,695 lb/ft2 abs Tat = 529.67 R Qg = 840/60 = 14.0 ft3/sec γ g = 0.0600 lb/ft3 w˙g = 0.0600(14.0) = 0.840 lb/sec w˙s = (π/4)(0.396)^2x(62.4x3.0x30)/(60x60)=0.192 lb/sec Dh = 0.396ft Dp = 0.198ft  eav = 0.0040ft f = 0.049  aa = 0.023 ba = 903.7 Tbh =Tr +0.01(1200) = 509.27 R Pbh = 5, 456 lb/ft2 abs = 37.9 psia Tav = 503.27 R Di = 0.166ft f = 0.019 ai = 0.019 bi = 7,610 Pin = 13860 lb/ft2 abs=96.2 psia P1=14.7 PSI p2=340+14.696=354.696 psia
  125. 125. SULLAIR Model 840 Rotary Screw Compressor pat = 11.76 psia Tat = 529.67 R Qg = 840/60 = 14.0 ft3/sec γ g = 0.0600 lb/ft3 ep = 0.0015ft f = 0.019 Di = 0.166ft w˙g = 0.840 lb/sec w˙s = 0.192 lb/sec Pin = 13860 lb/ft2 abs=96.2 psia ai = 0.019 bi = 7,610 Tav = 503.27 R P2= (340)+14.7 P1=14.7 fixed compression ratio rc: P2/P1= 24.14 Pd2 =rc x Pat  Pd2= 24.14 x 11.76 = 284.1 psia > 96.2 psia The last criteria to consider is whether the prime mover has the power to operate at the 6,000 ft surface elevation. Ws = 173.9  Was= 173.9/0.9= 193.2 HP is needed. Wi = 400 X (1− 0.148)= 340.8 HP > 193.2 HP
  126. 126. Gardner Denver Model WEN Reciprocating Piston Primary.  two-stage, reciprocating piston compressor  prime mover capable of a 270 HP at the speed of 1,000 rpm  producing a 700 scfm and a maximum pressure of 350 psig.  surface elevation = 6,000 ft | Pat = 11.769 psia |Tat= 70 F  Dh = 0.396ft | Dp = 0.198ft | ROP= 30 FT/HR | eav = 0.0040ft  Depth =1200 ft | Dpi = 0.166ft | es=0.00015 ft  SO: Pg=Pat=1,695 lb/ft2 abs Tg=Tat=529.67 R   γ g = 0.0600 lb/ft3 Qg = 11.7 ft3/sec  w˙ g = 0.0600(11.7)=0.7 lb/secDh = 0.396ft  f = 0.049 aa = 0.024 ba = 627.5  Tbh =Tr +0.01(1,200)= 509.27 Tav = 503.27 R  pbhi = 32.9 psia = = 4,732 lb/ft2 abs
  127. 127. Gardner Denver Model WEN Reciprocating Piston Primary.  pbhi = 32.9 psia = = 4,732 lb/ft2 abs  f=0.019ai= 0.019 bi = 5,285 Pin = 80.7 psia k=1.4  Po=80.74 Pi=11.77  ns=2 Qi=700  W˙s = 79.6 rs = (80.7/11.77)^0.5 = 2.62 εm=0.9  where c is the clearance volume ratio for the compressor model   W˙as = W˙s/(εm x εv) = 98.0 HP is the actual shaft power needed by the compressor to produce the 80.7 psia pressure output at the surface location elevation of 6,000 ft above sea level.  Wi = 270(1− 0.148(6000ft elevation effect)) =230 HP > 98 HP
  128. 128. Direct Circulation Models
  129. 129. Direct Circulation Models  Gases that are used most in drilling are air, natural gas, nitrogen or air stripped of oxygen.  Fluids used are treated fresh water, treated salt water, water based mud, diesel oil, oil based mud, and crude oil.  it is assumed that the rock particles move with the same velocity as circulating gas and fluid and that the resulting uniform. dh DDg fV dp ph mix         − += )(2 1 2 γ Pin: the injection pressure into the top of the drill string Pbdpi: pressure at bottom of drill pipe inside the drill string Pbdci: pressure at bottom of drill collars inside the drill string Pai: pressure above drill bit inside the drill string Pbdca: pressure at bottom of drill collars in the annulus Pbdpa: pressure at bottom of drill pipe in the annulus Pbca: pressure at the bottom of casing in the annulus Pe: pressure at the top of the annulus Derivation will start with the annulus, continues through the drill bit orifices, and then continue up the inside of the drill string to the surface. Derivation will start with the annulus, continues through the drill bit orifices, and then continue up the inside of the drill string to the surface.
  130. 130. Weight Rate of Flow of the Gas  In order to carry out the derivation of the governing equations for direct circulation, the weight rate of flow of air (or gas) to the well must be determined.  Three-Phase Flow in the Annulus:  volume of gas is changed as a function of pressure in path of circulation such as annulus: sec)/(sec)/( 3 ftactualQlbw RT SP ggg g gg g γγ =→= •  gmst ROP hs mmm wwww Dw Qw •••• • • ++= = = :flowofrateweighttotalThe )7.2)(4.62( 4 :solidstheofflowofrateweightentrainedThe :fluiddrillingibleincompress 2 κ π γ 2 460 H TT RT PS refave ave β γ ++=→=
  131. 131. Weight Rate of Flow of the Gas  The relationship between the weight rate of flow of the gas & the specific weight & volumetric flow rate of gas at any position in the annulus is given by: ( ) ( ) ( ) dh DD QQ T T P P DDg f QQ T T P P w dp dh DDg fV dp DD QQ T T P P DD QQ vel QQ T T P P w Q T T P P Q Q RT PS Q RT SP QQw ph mg g aveg ph mg g aveg t ph mix ph mg g aveg ph m mg g aveg t mix g g aveg ave g g g ggg                               − +               − +×               +               =⇒                          − += − +               = − + = +               =               = =⇒×=×= • • • 2 22 2 2222 4 )(2 1 )(2 1 44 . π γ ππ γ γγ
  132. 132. Weight Rate of Flow ( ) ( ) ( ) ( ) dpaiin bbhai ndmixbh t dd b b dn ph ph ph ph mg g aveg ph mg g aveg t a HP P aph mix PPP PPP DnCg w ACg Q gC V p pg CV e DD f f DD e f f v VDD DD QQ T T P P DDg f QQ T T P P w PB dh PB dP dh DDg fV dp bh e += ∆+=       × ===∆→ ∆ = ≥≤≤≤             +      − =               +         − −== − =                               − +               − +×               +               = =⇒         − += • • ∫∫ 2 2 2 2 2 2 2 2 2 22 0 2 4 2 22 2 4000Re4000Re20002000Re 14.1log2 1 Re 51.2 7.3 log2 1 Re 64 Re 4 )(2 1)( )()(2 1 π γ γ γγ γ π γ   
  133. 133. Stable Foam Drilling Model  In stable foam drilling operations, the mixture of gas (usually air or nitrogen) and water (with a surfactant) are specified (foam quality) at the top and, therefore, throughout the annulus.  The foam quality at the bottom of the annulus must be maintained at approximately 0.60 or greater & If drops, the foam will collapse and the flow will be in three separate phases.  To maintain the value about 0.60 or greater, the foam quality upstream of the back pressure valve is usually must be in the range 0.90 to 0.98.  where Pbp is the back pressure on the annulus.The value of C for this aerated fluid mixture is assumed to be 0.70 to 0.85.  Above Equ. must be solved by trial and error techniques since γ mixai depends on the pressure Pai. fg g QQ Q qualityfoam + =Γ= ∫ ∫= bh bp P P H a dh PB dP 0 )( 2 2 2 4 2       × =∆ • ndmixbh t bit DnCg w P π γ       −       × +≈       × +=∆+= •• aimixbh n t bh ndmixbh t bhbitbhai Dng w P DnCg w PPPP γγππ γ 11 44 2 2 2 2 2 2 2
  134. 134. Air and Gas Drilling Model  IfThere is two phase flow in the annulus (gas and rock cuttings). Qm = 0 ( ) ( ) ( ) ( ) ( ) 2 2 1 2 2 22 22 22 0 22 022 2 22 2 22 0 2 14.1log2 1 4000Re.turbulentisannulustheandstringdrillofinsideboth theinconditionflowthe :thatassumedisit 2 ln ln 2 1 4 )(2 1 4 )(2 1)( )()(2 1               +      − = >         −+= =      + + =+ = + ⇒                           − − =         +      =                               −               − +×                             = =⇒         − += ∫∫ ∫∫ • • • • e DD f TbeTbPP H T a TbP TbP h T a TbP dh T a TbP PdP DD w S R DDg f b w w R S a DD Q T T P P DDg f Q T T P P w PB dh PB dP dh DDg fV dp ph ava H T a avaatbh av a avaat avabh H av a P P ava H av a P P ava ph g ph a g s a ph g g aveg ph g g aveg t a HP P aph mix av a bh at bh at bh at π π γ
  135. 135. Stable Foam Drilling Model  For fluid mixtures that are nearly all gas (with little incompressible fluid), the pressure above the drill bit inside the drill string will depend upon whether the critical flow conditions exist in the orifices or nozzle throats.  For air (k = 1.4 ) the critical pressure ratio is 0.528 and for natural gas (k =1.28) the critical ratio is 0.549.  If the flow through the orifice or nozzle throat is sonic & does not depend on downstream pressure, Pbh:  Else the flow through the orifices or nozzles is subsonic and the upstream pressure will be dependent on the pressure and temperature at the bottom of the borehole annulus. 5.0 1 1 5.0 1 2               +       =       − + • k k n bhg ai kR gkS A Tw P 12 1 1 2 −•                     +       −           = k k bhbh n g bhai P k k g A w PP γ ∫ ∫= in ai P P H a dh PB dP 0 )(
  136. 136. Air, Gas, and Unstable Foam Drilling The majority of the operations use compressed air. In some cases it is necessary to drill with non support combustion gasses like natural gas & oxygen stripped atmospheric air (inert air)).
  137. 137. Air, Gas, and Unstable Foam Drilling  The basic planning steps for a deep well are as follows:
  138. 138. Minimum Volumetric Flow Rate  Engineering Practice:  The higher the velocity of the gas in the vertical flow line, the more the particle velocities approach the average velocity of the gas flow.  the larger the particles being transported the greater the slip velocity of the particle relative to the gas flow velocity.  As the gas flow rate decreases, cuttings begin to slip in the gas flow.This causes the cuttings transmit from the dilute phase solids flow to a dense phase solids flow.  When this occurs, the cuttings slow and the pressure forcing the gas to flow in the flow line increases. This condition is known as choking.
  139. 139. Minimum Volumetric Flow Rate  The lineAB in the figure refers to zero solids flow in the pipe (in our case the annulus).  A fixed solids weight rate flow, G˙1, at a high gas velocity (at point C), the solids volumetric concentration is low (well below one percent) and the particles are generally uniformly dispersed.This is dilute phase solids flow.  Decrease in gas flow rate (and velocity) leads to an increase in the pressure gradient.  curve EF indicates the dominance of the hydrostatic component. The solids concentration along curve EF is high and is dense phase solids flow.  The choking condition is rarely observed in actual vertical air or gas drilling operations.  This is due to two important air and gas drilling operational facts.
  140. 140. Minimum Volumetric Flow Rate  condition is rarely observed due to two air and gas drilling operational facts: 1) As the drill bit advances, the rotating drill string breaks up larger rock particles into smaller more easily transported particles when the larger particles collide with the drill string surface.  This breaking action occurs all along the drill string length, but is likely very pronounced around and just above the drill collars.  This mechanism has been observed in vertical drilling operations where down-hole pneumatic motors have been tested (drilling with no drill string rotation and with rotation) 2) The actual volumetric flow rate used in an air drilling operation is determined by the primary compressor output(s) to be used at the drilling location.  If the approximate minimum flow rate to the borehole is determined to be 1,000 scfm, and the compressors to be used to supply the compressed air are rated at 700 scfm each, then two compressors will be used to supply the air (1400 scfm , SF=1.4).
  141. 141. Engineering Planning Graphs  The minimum flow rate values are calculated assuming a minimum bottom-hole kinetic energy per unit volume of no less than 3.0 ft-lb/ft3.  Also, it is assumed that the drilling is in sedimentary rock formations with an average specific gravity of 2.7.  deep boreholes figures are developed for a uniform borehole diameter with the top two thirds of the depth assumed to be cased and the bottom one third assumed to be open-hole.  Illustrative Example 8.1:  CSG ID = 8.017” OH Interval = [7000’,10000’]  DC Length= 500’ DC OD = 6.75” DC ID = 2.812”  DP = 4.5’ 16.60 lb/ft Elevation= Sea Level  Temp.Grad.= 0.01 °F/ft ROP = 60 ft/hr  blooey line = 200’ blooey line ID = 8.097” 24 lb/ft Entire length of the borehole will be assumed to have diameter of 7.875”. Instead of the actual depth, a depth of 2/3 the total depth will be used. the 500 ft of DC OD change will ignored so DP OD=4.5”
  142. 142. Ex1. Engineering Planning Graphs ( ) 017.0 14.1 00015.0 375.0656.0 log2 1 14.1log2 1 sec/95.0 )60)(60( )60( )7.2)(4.62(656.0 4)60)(60( )4.62( 4 552 2 34.585)6667(01.0T R518.67459.67tTF59t sec/019.2 error)and(trial/secft26.488.1588 /0763.0 )67.519)(36.53( )0.1)(2116( 519.6760 abslb/21167.14 2 2 22 r rrr 3 3 2 =             +      − =               +         − = =            =            = °= + = °=+= °=+==→°= =×= == === °=°= == • • p ph ac shs cr avc bhg ggg g g g g at at e DD f lbSDw R TT T RT lbQw scfmq ftlb RT SP RFT ftpsiaP πκπ γ γ Rock Formation Types Surface Roughness (ft) Competent, low fracture - Igneous (e.g., granite, basalt) - Sedimentary (e.g., limestone, sandstone) - Metamorphic (e.g., gneiss) 0.001 to 0.02 Competent, medium fracture - Igneous (e.g., granite, basalt) - Sedimentary (e.g., limestone, sandstone) - Metamorphic (e.g., gneiss) 0.02 to 0.03 Poor competence, highly fracture - Igneous (e.g, breccia ) - Sedimentary (e.g., sandstone, shale) - Metamorphic (e.g., schist) 0.03 to 0.04
  143. 143. Ex1. Engineering Planning Graphs ( ) ( ) ( )( ) ( ) ( ) ( )( )( ) ( )( ) ( ) ( )( ) ( ) ( ) ( )( )( ) ( )( ) psiaP absftlbeTbeTbPP ba e DD f ft DD DeDe eftee R TT TRT absftlbeTbeTbPP ba DD w S R DDg f b w w R S a bh avoao H T a avoaoacbh acao avo ph ao ph pphoh avopoh cbh avocsg ava H T a avaatac acac ph g ph a g s a avo ao av a 4.93 /134501.6026.6741.6026.6748309 6.674 375.0656.0 4 019.2 1 36.53 )375.0656.0)(2.32(2 055.0 028.0 019.2 95.0 1 36.53 1 055.0 14.1 0076.0 375.0656.0 log2 1 14.1log2 1 0076.0 44 44 00015.001.0 1.602 2 67.618)10000(01.0T /83095521.2095521.2092116 1.209 375.0656.0 4 019.2 1 36.53 )375.0656.0)(2.32(2 017.0 028.0 019.2 95.0 1 36.53 1 4 )(2 1 2 2 1 23333 1.602 028.02 22 2 1 2 2 22 2 22 2 2 22 22 r 2 2 1 26667 552 028.02 22 2 1 2 2 22 2 22 2 22 = =        −+=         −+= =             − − ==    +      = =             +      − =               +      − = =       +            +      =→== °= + =⇒°=+= −−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− =        −+=         −+= =             − − ==      +      =             − − =         +      = × × • • • π ππ ππ π π
  144. 144. Ex1. Engineering Planning Graphs  Below Figure gives the air minimum flow rates for a 4 1/2 inch drill pipe in a 7 7/8 inch borehole.  This example demonstrates how these figures were developed.  Assume the drilling location is at 4,000 ft above sea level so:  We let weight rate of gas be constant @ surface:  pat = 1,827 lb/ft2 abs Tat = 519.67 R γ g = 0.0659 lb/ft3  Qsurf from Figure @ sea Elevation = 1588.8 scfm ( ) ( )[ ] 3 4 2 22 3 3 003.3 sec 0126.0 2.32 407.0 sec/8.21 375.0656.0 4 964.4 /secft964.4 407.0 019.2 /407.0 )67.618)(36.53( )0.1)(13450( ft lbft KE ft lb ftV w Q ftlb RT SP bh bhgbh gbh g gbh g bh gbh − = − === −      = === === • ρ π γ γ acfmElevationQsurf 1840 0659.0 0763.0 8.1588'4000@ =      =
  145. 145. Major and Minor Losses and Injection Pressure  It is important to determine the injection pressure, this value is compared to the Max output capability of the compressor.  If the value is less than the Max press. capability of the compressors, then the compressor system is tentatively capable of providing compressed air to the drilling operation.  The prime mover of the compressor must be checked to ascertain if it is capable of producing the power needed to produce the required pressure.  The power of a prime mover is sensitive to its elevation & will decrease as the elevation above sea level is increased.  Some extra Minor Losses calculating for more accuracy: • blooey line upstream • Changes in annulus and drilling string geometry • Geothermal fluids recovery  A properly designed drill string with Min Pbh causes less formation damage.
  146. 146. Injection Pressure and Selection of Compressor Equipment  Illustrative Example 8.1:  CSG ID = 8.017” OH Interval = [7000’,10000’]  DC Length= 500’ DC OD = 6.75” DC ID = 0.812”  DP = 4.5’ 16.60 lb/ft Elevation= 4000’  Temp.Grad.= 0.01 °F/ft ROP = 60 ft/hr  Blooey line = 200’ Blooey line ID = 8.097” 24 lb/ft  Pat = 1,827 lb/ft2 abs Tat = 44.74 F  γ g = 0.0659 lb/ft3 Q every compressor = 1200 acfm  Q Min = 1840 acfm Qg = 2x1200 = 2,400 acfm  A short 1 1/2 ft long tool joint every 30 ft along of DPs. ( ) sec/95.0 )60)(60( )60( )7.2)(4.62(656.0 4 )60)(60( )4.62( 4 sec/019.2 R41.045459.67tTF44.74t 2 2 rrr lb SDw lbQw shs ggg =            =            = =×= °=+==→°= • • π κπ γ
  147. 147. Blooey Line  It is assumed that the air will exit the well annulus and enter the blooey line with the surface geothermal temperature of 44.74˚F.  The isothermal gas flow equ. Is used for major loss due to pipe wall & minor losses: • T turn at the top of the annulus • two valves at the entrance end of the blooey line. ( ) ( )( ) ( ) ( ) ( ) absftlb P SgA RTw KK D fL P e D f DALeD at b gg Vt p b bh p b b bbbpb 2 2 1 2 2 2 2 1 2 2 2 2 2 /21631827 1358.0)2.32( 41.50436.53635.2 )2.0(225 668.0 200)014.0( 014.0 14.1log2 1 358.0 4 '200'00015.0'668.0 =         +            ++=           +                   ++= =               +         = =      ==== • ∑ π
  148. 148. Ex. Minor losses  Geometry in the Annulus: ( ) ( ) ( )( ) ( ) ( ) ( )( )( ) ( )( ) psiaftlbPfba R psiaabsftlbeTbeTbPP ba e DD f RTR HHH HH DDDDD aaaa ava H T a avaata aa avo ph a av h av a 8.80/11640021.04476025.0 66.572 2 TT TR574.41)H0.01(HTT 5.64/928566.5377.30466.5377.3042164 7.304 375.0668.0 4 635.2 1 36.53 )375.0668.0)(2.32(2 017.0 025.0 635.2 95.0 1 36.53 1 017.0 14.1 0015.0 375.0668.0 log2 1 14.1log2 1 66.53791.5700.01(6650)TT :ft)7,000to(SurfaceAnnulustheofSectionCased '500'125 30 2500 5.1'2375 30 2500 5.15003000 '350 30 7000 5.1'6650 30 7000 5.17000 '563.0'656.0'552.0'375.0'668.0 2 2222 21 av221r2 2 2 1 26650 66.537 025.02 22 2 1 2 11 2 2 11 2 1 2 22 11 2 2 1 1r1 543 21 4321 1 1 ===== °= + =→°=++= ==        −+=         −+= =             − − ==    +      = =             +      − =               +      − = °=→°=+= ==      ==      −−= =      ==      −= ===== × π
  149. 149. Ex. Minor losses  Geometry in the Annulus:  In general, jetting nozzles are only used when down-hole motors are used. ( )( ) ( )( ) psiaabsftlb P k k g A w PP ftlb psiaftlbPfba R psiaftlbPfba R psiaftlbPfba R k k bhbh n g ai a aaaa aaaa aaaa 6.217/313301 1 2 /913.0 41.60436.53 0.129454 ft0.00802Ao0.0583'D :)0.70"ofdiameterinsideaneach withorifices,open(threeOrificesOpenBitDrill 5.204/29454079.032210025.0 91.601 2 TT TR41.604)HHHH0.01(HTT 5.129/18643076.022870025.0 79.598 2 TT TR41.995)HHH0.01(HTT 3.111/16030055.011490025.0 29.586 2 TT TR16.985)HH0.01(HTT :ft)10,000ft to(7,000AnnulustheofSectionOpenhole 2 12 55 3 5 2 o 2 5555 54 av554321r5 2 4444 34 av44321r4 2 3333 32 av3321r3 ==                     +       −           = ===→= ===== °= + =→°=+++++= ===== °= + =→°=++++= ===== °= + =→°=+++= −• γ γ
  150. 150. Ex. Minor losses  Geometry Inside the Drill String:  This result required to force a flow rate of 2,400 acfm through the circulation system. psiaftlbPfba R psiaftlbPfba R psiaftlbPfba R psiaftlbPfba R psiaftlbPfba R iniii iiii iiii iiii iiii 4.212/30590016.02486019.0 66.537 2 TT TR91.075)0.01(HTT 5.226/32620017.03958019.0 66.572 2 TT TR4.4175)H0.01(HTT :Surface)ft to(7,000StringDrilltheInside 9.225/32540016.02486019.0 29.586 2 TT TR16.985)HH0.01(HTT 5.229/33050017.03958019.0 79.598 2 TT TR41.995)HHH0.01(HTT 2.229/33010018.012420019.0 91.601 2 TT TR41.604)HHHH0.01(HTT :ft)7,000ft to(10,000StringDrilltheInside 0.319'D0.292'D0.234'D 2 111 at1 av11r1 2 1222 21 av221r2 2 2333 32 av3321r3 2 3444 34 av44321r4 2 4555 54 av554321r5 765 ===== °= + =→°=+= ===== °= + =→°=++= ===== °= + =→°=+++= ===== °= + =→°=++++= ===== °= + =→°=+++++= ===
  151. 151. Ex. Minor losses  The prime mover for this compressor is a diesel fueled, turbocharged, Caterpillar Model D398 with a peak output of 760 HP at 900 rpm (at API standard conditions).  The prime mover of each of the two compressor derated input power is greater than the actual shaft horsepower needed so the selected compressor units can be operated. ( ) ( )[ ]{ } ( )( ) 9.24926840.10)760(1.W 9.249 922.09.0 4.207 )( 9.0922.0102.206.0196.011 02.2 685.12 1.212 4.2071 685.12 1.212 17.229 2 2400 658.12 14.1 4.14 )( 1 17.2291 )( i 4.1 1 1 4 1 4.14 4.0 1 1 1 2 ×>== == ==−−=               −−= =      == =           −                  − × =       ==           −                  − = • ו − • HPW rc rrationCompressio HPW P P rrationCompressio P Pqp k kn HPW as m k sv s s n i o s kn k iis s s s εε
  152. 152. Water Injection  Water is injected into the flow rate of gases flowing from the compressors to the top of the inside of the drill string for three important reasons:  The air or other gas with water vapor at bottom-hole annulus pressure and temperature conditions.  Eliminate the stickiness of the small rock cuttings flour generated by the advance of the drill bit  Assist in suppressing the combustion of the mixture of produced hydrocarbons and oxygen rich air.  The liquid pump draws its water from a liquid.Additives: corrosion inhibitors, polymer, and a foamer.  Mist” injection defines injection of water with additives as unstable foam drilling operations. Additives per 20 bbls of Water Foamer 4.2 to 8.4 gals Polymer 1 to 2 quarts Corrosion Inhibitor 0.5 gals
  153. 153. Saturation of Gas at Bottom-hole Conditions  Water is injected to the gases at the surface to saturate the gas @ bottom-hole & if water is not injected a portion of the formation water will be absorbed by the gas as water vapor.  This process decreases the internal energy in the gas as the gas enters the annulus & dramatically reduces the kinetic energy causes reducing in carrying capacity of the gas.  This is the most efficient method of carrying an influx of formation water from the annulus of a well. In general, it is not efficient to try to use dry gas to absorb formation water as a water vapor and, in essence, “dry-out” a well.  The empirical formula for determining the saturation of various gases including air:  Thus, the flow rate of injected water, qiw, is determined from:  Nearly all injected water is injected with additives. psia3.25110 74.144555.023.217 286.1750 39416.6 = →= °=                + − Ftt sat bhbh P ( ) hrgalw PP P g satbh sat /5.18635.2 33.8 3600 251.35.204 251.3 33.8 3600 qiw =            − =            − = •
  154. 154.  After water injection determining the amount of carrying capacity of formation water is urge. it can be assumed that the formation water will be carried from the well as droplets.  Since the gas flow rate is greater than the Min flow rate then the extra flow rate will allow a much greater ROP, that the gas flow rate can support more droplets of formation water.  The additional ROP can be converted to a weight or volumetric flow rate of formation water that can be carried from the well.  Illustrative Example 8.6:  The influx of formation water that can be carried from Illustrative Example 8.3 (SG=1.07)  Q=2400 acfm ROP max = 400(1− 0.20)=320 Saturation of Gas at Bottom-hole Conditions ( ) ( ) ( ) 3600 )33.8)(42( 3600 )33.8)(42( 11 /40/1663 07.133.8 7.24.62 60320656.0 433.8 4.62 4 2 max 2 fw fw iw iw g iw i g fwiws a fw s hfw q w q w w w R S a w www R S a hrbblhrgal S S Dq ==         +      =         ++ +      = ==      × × −=         × × −= •• • • • ••• π κκ π
  155. 155. Saturation of Gas at Bottom-hole Conditions  Illustrative Example 8.7:  Determine the BHP and INJ.P for Illustrative Example 8.3 series if Qiw = 2 bbl/hr.  Determine the BHP & INJ.P for flow rates of formation water of 0 to 35 bbl/hr. SGw= 1.07.
  156. 156. Eliminate Stickiness  The next level of injected water flow rate w/ additives is that needed to eliminate stickiness.  As the bit advances in some rock types, rock particles and “rock flour” are created & If a borehole be dry, the air will efficiently carry the cutting particles and the rock flour up the annulus to the surface.  If a water bearing formation is drilled, formation water will begin to flow into the annulus & combines with the rock flour that causes being stick to each other & sticks to the nonmoving inside surface of the borehole.  Because the gas flow eddy currents form just above the top of the drill collars, “mud rings” of this sticky rock flour form at this location on the borehole wall.
  157. 157. Eliminate Stickiness  These mud rings can create a constriction to the annulus gas flow causes the INP increase slightly (by 5 to 10 psi) in a matter of a minute or so.  If mud rings are allowed to form they will begin to resist the rotation of the drill string & the applied torque increases and increase the danger of a drill string torque failure.  The existence of mud rings creates a confined chamber of high pressure air.If hydrocarbon rock formations are being drilled,the potential for ignition increases.  The solution to this operational problem is to begin to inject water into the circulation gas.  Additional injected water is needed to reduce the stickiness & must be determined experimentally and will be somewhat unique for each drilling operation.
  158. 158. eliminating mud rings  The procedure for eliminating mud rings is as follows: 1. Begin injecting sufficient water to saturate the gas flow with water vapor. 2. Curtail drilling ahead but continue gas circulation. 3. Bring the rotations of the drill string up to about 100 rpm and lift the drill string up to the top of the drilling mast and lower it several times.This will allow the drill collars to smash into the mud ring structures and break them off the borehole wall. 4. Return to drilling ahead. 5. If the mud rings begin to form again (the injection pressure increases again), increase the water injection flow rate and repeat the above sequence. 6. Continue the above five steps until the volumetric flow rate of injected water reduces the stickiness of the rock flour so that the mud rings no longer form on the open borehole wall.
  159. 159. Suppression of Hydrocarbon Ignition  The next higher level of water injection flow rate is the volume needed to suppress the ignition of down-hole explosions and fires due to the mixture of circulation air with produced oil, natural gas, or coal dust and fragments as the drill bit is advanced.  Higher level of water injection flow tends to be successful in vertical wells but not successful in horizontal boreholes because vertical wells tend to penetrate the vertical thickness of the hydrocarbon producing reservoir.  The vertical thickness of these reservoirs tend to be of the order of a few hundred feet.Thus, at a drilling rate of 60 ft/hr, the exposure time in the hazardous production zone is only a few hours.  On the other hand, horizontal boreholes require the drilling of several thousands of feet of open-hole in the hydrocarbon bearing reservoir.The drilling rates in horizontal boreholes are usually about half the drilling rates in vertical wells.
  160. 160.  There are other drilling methods that can be used to suppress or eliminate ignition such as use of gases that will not support ignition like natural gas, nitrogen based gas , inert air.  The use of these other drilling gases can significantly increase drilling operation costs.  Natural gas presents the somewhat greater hazard relative to exposure to oil and coal.  Hazard of ignition increases with higher pressures so the deeper the drilling operation & in turn the ignition probability in the presence of hydrocarbons. Suppression of Hydrocarbon Ignition
  161. 161. Suppression of Hydrocarbon Ignition  Below figure are only applicable for vertical boreholes in which the exposed oil and natural gas producing reservoirs, and solid coal seam thicknesses are of the order of 200 ft or less.  As in any air drilling operation, constant supervision is necessary. But air and gas drilling are unique in that the warning signs of down-hole problems are usually in the form of rapid increases of injection pressures of as little as 5 to 10 psi.
  162. 162. Suppression of Hydrocarbon Ignition  The following steps should be taken to prevent down-hole ignition in hydrocarbon bearing formation: 1. Drilling should be immediately stopped. 2. Air injection should be shut off and the gas flare monitored. If the flare is sustained, the operator should note the wetness of the cuttings at the sample catcher(yellow color of burning gas sparks at the end of the blooey line (indicating drill cuttings are damp from distillate). If the gas flare will not sustain or burn when air is turned off, air should be turned back on. 3. With the air turned on and flowing to the well, and it has been determined that the gas is wet, no drilling should be carried out since rock flour and cuttings will likely form mud rings.With air on, raise and lower the drilling string with the drill string rotating at approximately 100 rpm to smash up existing mud rings and prevent formation of new mud rings. 4. If the gas is wet (with water or distillate), begin the injection of water and additives into the injected air flow. Begin to drill with unstable foam circulation fluid. 5. If the gas is dry and there are no sparks and no black smoke nor wet samples at the surface, drill 5 to 10 ft and then raise and lower the drill string to avoid a pressure increase due to mud rings. Continue drilling at 5 to 10 ft until the wet gas condition does not exist.
  163. 163. Sloughing Shale Problem  Since the drilling circulation fluid is not heavy, there is a constant threat of caving and sloughing of the open- hole borehole wall.  Air and gas drilling will have ROP that can be twice that of mud drilling operations that is an important feature since open-hole integrity is very dependent upon the length of time the hole remains open and unsupported by cement and casing.  When shales are penetrated with a bit, the open-hole surfaces of the exposed shales tend to break off and the large fragments fall into the annulus space between the open-hole and the DCs & DP OD surfaces that can be temporarily controlled by injecting additional additives into water being injected into the circulation air or gas.  sloughing shale control additives: Additives per 20 bbls of Water Foamer 8.5 gals Bentonite 40 lbs CMC 2 lbs Corn Starch 5 lbs Soda Ash 1 quart
  164. 164. Casing and Cementing Problem  When drilling with air or gas, the borehole will be basically dry when the borehole is cased and cemented.The well is not filled with treated water and the casing is floated into the well (making use of buoyancy) as is done in mud drilling operations.  This presents some special problems for air and gas drilling operations.  When an open-hole section of a gas drilling well is to be cased, the casing is lowered into the dry well.  A pre-flush of about 20 bbls of CMC treated water must be pumped inside the casing just prior to pumping the cement.
  165. 165. Casing and Cementing Problem  A bottom plug is run & another bottom plug run ahead of the cement, & a final top plug run behind the cement. Fresh water is pumped directly behind the top plug and fills the inside of the casing to the surface.  The CMC seals the surface of the dry borehole walls prior to the cement and precludes the cement from hydrating as it flows from the inside of the casing to the annulus between the openhole and the outside of the casing.  If the pre-flush is not used the initial cement flowing through the casing shoe to the untreated open- hole of the borehole will immediately set-up and disallow the remaining cement to flow to the annulus.  After cementing it is necessary to remove the water from inside the casing in order to return to gas drilling operations.

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Incompressible Fluids 1. static Well Conditions • Hydrostatic Pressure in Liquid Columns • Hydrostatic Pressure in Mixed Columns • Kick Identification • Buoyancy and Effect of Buoyancy on Buckling 2. Non-static Well Conditions • Flow Through Jet Bits • Shear Stress V.S. Shear Rate (Laminar) 3. Rheological Models • Newtonian • Non-Newtonian • Rotational Viscometer • Initial Circulating of Well 4. Laminar Flow In Pipes & annulus • Newtonian Flow In Pipes & annulus • Newtonian Flow In Pipes & annulus (As a Slot) 5. Turbulent Flow In Pipes & annulus • Moody Diagram • Critical Velocity • Hanks Turbulence Criterion 6. Extension Equations For Flow • Hydraulic Radius • Apparent Viscosity 7. Jet Nozzle Size Selection • Pressure loss Simplification • Maximum Nozzle Velocity • Maximum Bit Hydraulic Horsepower • Maximum Jet Impact Force • Minimum needed annular Velocity 8. Surge and swab pressure of Vertical Pipe Move 9. Particle Slip Velocity 10. Known Cleaning Needs Compressible Fluids 11. Basic Technology • Introduction • Surface Equipment • Down hole Equipment • Compressors • Shallow Well Drilling Applications 12. Circulation Systems • Reverse Circulation • Direct Circulation 13. Comparison of Mud and Air Drilling • Pressure profile • Heat capacity • Density profile • Kinetic energy profile 14. Surface Equipment Summery • Drilling Location • Flow Line to the Rig • Wellhead Equipment • Flow Line from Rig 15. Downhole Equipment Summery • Rotary Drill String • Drill Bits • Bottom hole Assembly • Drill Pipe • Safety Equipment • Drill String Design 16. Compressors type Nominations • Continuous Flow • Intermittent Flow 17. Power Requirements • Single Stage Shaft • Multistage Shaft • Prime Mover Input 18. Reciprocating Compressor Unit 19. Shallow Well Drilling Applications • Shallow Well Drilling Planning • Direct Circulation • Reverse Circulation • Direct Circulation Based on Weight Rate of Flow • General Derivation • Wet and Dry Air and Gas Drilling Model • Unstable and Stable Foam Drilling • Aerated Fluid Drilling Model 20. Direct Circulation Hydraulic Sections • the injection pressure into the top of the drill string • pressure at bottom of drill pipe inside the drill string • pressure at bottom of drill collars inside the drill string • pressure above drill bit inside the drill string • pressure at bottom of drill collars in the annulus • pressure at bottom of drill pipe in the annulus • pressure at the bottom of casing in the annulus • pressure at the top of the annulus 21. Air and Gas Drilling Models • Deep Well Drilling Planning • Minimum Volumetric Flow Rate • Terminal Velocities • Injection Pressure and Selection of Compressor Equipment • Prime Mover Fuel Consumption • Water Injection • Drilling and Completion Problems 22. Major & Minor Loss & Injection Pressure • Non-Frictional Approximation • Frictional Approximation

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