Drilling Tech Hydraulics

Wellbore HydraulicsPresentation 12

Tod StephensAmericas Deepwater Ventures

Drilling Engineer

DRILLING TECHNICIAN SCHOOLExxonMobil Development Company

Houston, Texas2004

Lesson Objectives

• List the major parts of the mud pump and determine the correct liner size for a given set of drilling parameters.

• List the 5 major parameters that need to be considered when optimizing the hydraulic system.

• List the 3 parameters that need to be considered when estimated the optimal flow rate.

• List 8 things that need to be considered when evaluating ECD.

• What are the two most common methods for optimizing bit hydraulics and in which case would you choose one over the other.

Lesson Objectives

• Calculate the appropriate nozzle sizing for a given TFA.• Calculate the pressure drop in the drilling string and

annulus for a give flowrate.• List 7 possible sources of inaccuracy when estimating

pressure loss through the circulating system.• List 3 ways to reduce the pressure loss through the

circulating system.• List 6 parameters that contribute to surge and swab.• List five possible uses of PWD data• 5 responsibilities of the DT with regards to hydraulics

Lesson Outline

• Functions of Circulating System

• Components of the Circulating System

• Pump requirements - Pressure & Flow Rate

• Optimal flow rate for Hole Cleaning and Equivalent Circulating Density (ECD)

• Bit hydraulics - Hydraulic Horsepower & Impact Force

• Calculating pressure losses in system

• Hydraulics related design issues

• Surge and Swab / Breaking Circulation

• PWD data - collection & interpretation

• What can I do

Functions of the Circulating System

• To clean the bottom of the hole

• To cool the bit and lubricate the drill string

• To transport the cuttings to the surface

• To support the walls of the wellbore

• To prevent entry of formation fluids into the wellbore

Circulating System

1 - Mud Tank 2 - Centrifugal Pump 3 - Mud Pump 4 - Pulsation Dampener 5 - Standpipe 6 - Swivel 7 - Kelly 8 - Drill Pipe 9 - Drill Collar10 - Drill Bit11 - BOP12 - Bell Nipple13 - Flow Line14 - Shale Shaker

1 2

3

5

4 7

6

8

9

10

11

12

13

14

Mud Pump Overview

• Mud pumps supply hydraulic energy

• Everything else in the circulating system consumes energy

• To size a pump / liners, we need to calculate all of the frictional pressure losses in the system for the desired flowrate

• The standpipe limitations also need to be considered

Mud Pump

• 500 to 2200 HP– 80 to 1215 GPM– 0 to 7500 psi

• Triplex– fixed stroke length– vary liner diameter

• Triplex efficiency– Volumetric (Ev) = 93%

– Mechanical (Em) = 90 %

Mud Pump

• Hydraulic Horsepower– Mud pumps are rated on the basis of Input Horsepower:

Rated Input HP = P x Q1714 x Em x Ev

– Or, Output HHP = Rated Input HP x Em x Ev

where: Q = Flow rate, gal/min P = Circulating pressure, psi Em = Mechanical efficiency of pump, % Ev = Volumetric efficiency of pump, %

Mud Pump

National 8-P-80 Performance Chart8-1/2" stroke length, 800 input horsepower at 160 strokes per minute

6.25 6 5.5 5 4.5 42280 2470 2940 3560 4395 5000

Pump Speed, SPM Max Input HP *HHP GPM GPM GPM GPM GPM GPM**160 **800 720 542 500 420 347 281 222140 700 630 474 437 367 303 246 194120 600 540 406 375 315 260 211 166100 500 450 339 312 262 217 176 13980 400 360 271 250 210 173 140 111

3.386 3.121 2.622 2.167 1.755 1.387

* Based on 90% mechanical efficiency and 100% volumetric efficiency.** Rated speed and input horsepower

Liner Size, inchesMax. Dischg. Pres, psi

Vol/stroke, gal.

Mud Pump

• Efficiency Calculations– 120 SPM, 6-1/2” Liner

Output HHP = 600 x 90% x 100% = 540 HPPOutput HHP = Rated Input HP x Em x Ev

– But what if Ev = 93%

Output HHP = 600 x 90% x 93% = 502 HPP

Output HHP = P x Q1714

Q = 1714 x 502

2280= 377 gpm

Mud Pump

Pump Liner Size Vs Discharge Pressure / Flow Rate

2000

2500

3000

3500

4000

4500

5000

5500

4 4.25 4.5 4.75 5 5.25 5.5 5.75 6 6.25

Pump Liner Size, in

Ma

xim

um

Dis

ch

arg

e P

res

su

re, p

si

0

50

100

150

200

250

300

350

400

450

Ma

x F

low

Ra

te, g

pm

Discharge PressureFlow Rate 100% EvFlow Rate 93% Ev

Pump Data: National 8-P-80Flow rate @ 120 SPM90% Em

Mud Pump

• Volume Calculations (Triplex)– 6-1/4” Liner, 8-1/2” Stroke

Where: VC = Volume per cylinder, bbl LS = Liner size, in SL = Liner length, in

Volume per Stroke (BPS) = VC x 3

Volume per Stroke (GPM) = BPS x 42

LS2 x SL

1029.4 x 12Vc =

Mud Pump Exercise

• Drilling 6-1/4” from 8500’ MD to 12,000’ MD which historically has taken 2 bits. Estimated starting pressure 2200 psi and ending pressure 2600 psi. The required flow rate is 300 gpm and the drilling contractor will only run the pumps 110 SPM (maximum). The Ev is ~93%.– What is the appropriate liner size? – Can one liner size make the entire hole section?

Mud Pump Exercise

1) Estimate the appropriate liner size to start the hole.

2) Interpolate between 120 SPM and 100 SPM, to calculate flowrate 110 SPM.

3) Calculate flowrate with an efficiency of 93%Answer: 319 gal/min

Answer: 343 gal/min

Answer: 6”

Mud Pump

Crankshaft Crosshead

Extension Rod

Fluid End

Power End

Pinion Shaft

Eccentric Strap

Mud Pump

Piston Rod

Fluid End

Liner

Piston

Suction Module

Discharge Module

Suction

Discharge

Valve

Seat

Valve Cover

Mud Pump

Pulsation Dampener

Nitrogen Filled Bladder

Mud Pump “Power End”

Gear

Crankshaft

Pinion Shaft

Eccentric Straps


Crosshead

Eccentric Strap

Pinion Shaft


Crosshead

CrossheadGuide

Mud Pump “Fluid End”

Block Manifold

Suction

Cylinder Head

Mud Pump “Fluid End”

Valve Seat

Piston Rod

Piston

Wellbore Hydraulics Design

• Hole cleaning and avoiding lost returns

• Bit nozzle optimization

• Drill string design

• Determining mud pump / standpipe pressure requirements

• Flow rate requirements for downhole tools– MWD / LWD– PDM

Optimizing Flow Rate

• Annular Velocity “Hole Cleaning”• ROP “Bit Hydraulics” • Operate Down Hole Equipment

– PDM (Motor or Turbine)– MWD / LWD / PWD


• Annular Velocity– The speed of the fluid moving up the annulus.– Must be high enough to keep the cuttings moving upward at a

sufficient rate, but not so high that the hole is washed out.– Penetration rate, carrying capacity of the drilling fluid, and type of

formation being drilled effect the velocity required to clean the hole.


• Annular Velocity “AV”– AV = (24.51 x Q) / (Dh

2 - Do2)

– AV = annular velocity, ft/min– Q = flow rate, gal/min– Dh = hole diameter or casing ID, in

– Do = outside diameter of either the drill pipe or collars, in

• Rule of Thumb - 120 ft/min minimum AV

– 17-1/2” hole: 1200 - 1500 gpm

– 12-1/4” hole: 700 - 1200 gpm

– 8-1/2” hole: 350 - 750 gpm (check ECD)

– 6” hole: 200 - 300 gpm (check ECD)


Flowrate vs Annular Velocity

50

75

100

125

150

175

200

400 500 600 700 800 900 1000

Flowrate, gpm

An

nu

lar

Ve

loc

ity

, ft

/min

12-1/4" Hole

12-1/2" Hole

13" Hole

13-1/2" Hole

14" Hole

120 ft/min "Rule of Thumb"

Drilling 12-1/4" Hole with 5" Drill Pipe


• Slip velocity (Cuttings Transport)– hole angle

– washout

– cuttings size

• ROP & Cuttings Bed Height - Hole Cleaning Ratio (HCR)

• Equivalent Circulating Density (ECD)

Hole Cleaning Ratio “HCR”

• Cuttings Bed Height– The height of a cutting bed with the drill pipe on the low side of the

wellbore. Cuttings beds are stationary in high angle wells (> 50 degrees) but they are avalanching in intermediate angle wells (between 20 and 50 degrees).


• Bit Open Area– The minimum open area between the bit body and a gauge hole,

expressed as a percentage of the cross-sectional area of the gauge hole. For PDC bits, it is typically the Junk Slot Area (JSA). For rock bits, it is the minimum open area around the bit.


• Hole Cleaning Ratio “HCR”– An empirical correlation to indicate hole cleaning problems while

pulling out of the hole. Or in other words, to measure the ability to pull a bit/BHA through the cuttings bed.

– When HCR is greater than 1.1, the bit/BHA can be pulled through the cuttings bed. When the HCR is less than 1.1, the bit/BHA can have difficulties pulling through the cuttings bed.



Flowrate vs HCR / Cutting Bed Height

3.0

3.5

4.0

4.5

5.0

5.5

6.0

700 800 900 1000 1100 1200

Flowrate, gpm

Cu

ttin

gs

Be

d H

eig

ht,

in

0.8

0.9

1

1.1

1.2

1.3

1.4

HC

R

Cutting Bed Height, inHCR

Target HCR = 1.1

Parameters: Hole Size = 12.25" DP = 5" Inclination = 60 deg ROP = 50 ft/hr, Mud = 10.7 ppg WBM Rotary = 50 rpm


ROP vs HCR

0.8

0.85

0.9

0.95

1

1.05

1.1

1.15

1.2

50 60 70 80 90 100

ROP, ft/hr

HC

R

12-1/4" Hole

12-1/2" Hole

13.0" HoleTarget HCR = 1.1

Parameters: Bit Size = 12-1/4" DP = 5" Inclination = 60 deg Mud = 10.7 ppg WBM Rotary = 50 rpmFlowrate = 900 gpm

Equivalent Circulating Density

ECD is the hydrostatic head of the mud column plus the circulating frictional pressure losses in the annulus

ECD = MW +Pannulus

0.052 TVD

where: ECD = equivalent circulating density (ppg)MW = mud weight (ppg)Pannulus = pressure loss in annulus (psi)TVD = true vertical depth (feet)

• ECD depends on – flow rate & wellbore ID/drill pipe OD

– well depth and profile

– downhole temperature / pressure

– cuttings in flow stream and beds

– mud properties

– drill string rotation

– hole washouts

– eccentric drill string

Causes of ECD

Cuttings Bed Effect

0

2000

4000

6000

8000

10000

12000

0 20 40 60 80 100

Inclination (degrees)

MD

(ft

)

0

2000

4000

6000

8000

10000

12000

0 20 40 60 80 100

Inclination (degrees)

MD

(ft

)0

2000

4000

6000

8000

10000

12000

0 1 2 3 4 5

Cuttings Bed Height (inches)

0

2000

4000

6000

8000

10000

12000

0 1 2 3 4 5

Cuttings Bed Height (inches)

13-3/8” Casing

12 1/4” Open Hole

Suspended cuttings

Cuttings bed

ECD vs Measured Depth

ECD (ppg)ECD (ppg)

MD

(ft

)M

D (

ft)

Suspended cuttings

Suspended cuttings

Local Mud Weight (ppg)Local Mud Weight (ppg)

• To prevent lost returns, ECD < fracture gradient

• In deepwater wells, the margin between pore pressure and fracture gradient can be low

• In extended-reach wells (ERW), ECD can be high due

– Need for higher circulating rates and rotational speeds for hole cleaning

– MD/TVD ratio (same pressure loss at shallower depths)

– Often larger DP (I.e. 5-1/2” vs 5”)

Significance of ECD

ECD in Deepwater

ECD from ERD Wells

ECD due to Drill String Rotation

Flow Rate

Rotation 280 GPM 365 GPM 440 GPM

0 RPM 10.24 ppg 10.35 ppg 10.52 ppg

40 RPM 10.34 ppg 10.54 ppg 10.74 ppg

80 RPM 10.44 ppg 10.64 ppg 10.81 ppg

120 RPM 10.49 ppg 10.71 ppg 10.91 ppg

Sacate SA-2Sacate SA-2ECDs from PWD Data with 9.3 ppg Escaid MudECDs from PWD Data with 9.3 ppg Escaid Mud

Bit inside 9-5/8-inch casing at 22,295 ftBit inside 9-5/8-inch casing at 22,295 ft4-1/2 x 5-1/2-inch drill pipe4-1/2 x 5-1/2-inch drill pipe

No cuttingsNo cuttings

Flowrate Summary

Action AV HCR ECDIncrease drill pipe size to 5-1/2" from 5" in 12-1/4" holeIncrease flow rate from 600 to 800 GPM in 12-1/4" holeDecrease ROP (at constant flow rate)Increase drill pipe rotation (at constant flow rate)

Bit Hydraulics

• Bit hydraulics enhance the mechanical action of the bit through three major mechanisms.

– The removal of the cuttings at the same rate at which they are generated.

– Cutting structure cleaned to prevent the accumulation and packing of material between the cutting elements.

– Bottom scouring to remove filter cake and crushed material from the borehole bottom.

• The pressure at the bit multiplied by the flowrate is a measure of the power available for cleaning the borehole bottom.

Bit Hydraulics

• Maximum Hydraulic Horsepower Method

– The borehole bottom is best cleaned when the hydraulic horsepower at the bit is at a maximum.

– Pressure drop across the bit is 65% of the total pump pressure.

– Units: Hydraulic Horsepower (hhp) or HSI

• Maximum Impact Force Method

– The borehole bottom is best cleaned when the force exerted by the jets is at a maximum.

– Pressure drop across the bit is 48% of the total pump pressure.

– Units: Impact Force (lbf)

Bit Hydraulics

• Borehole depth and the downhole conditions determine which optimization method should be used.

• Surface Hole - high ROP and large volume of cuttings generated.

– Maximizing Impact Force is best

• Production Hole - Deep, smaller diameter, lower ROP, small volume of cuttings generated.

– Maximizing Hydraulic Horsepower is best

• Field history and equipment limitations must be considered in determining bit hydraulics.

Bit Hydraulics

Maximum Impact and HHP at the Bit

Increasing Flowrate

Pu

mp

Pr e

ssu

r e

Bit Hydraulics Basic Equations

• Hydraulic Horsepower

Hb = Pb x Q

1714where: Hb = hydraulic horsepower at the bit, hp

Q = flow rate, gal/min Pb = pressure drop at bit, psi

• Hydraulic Horsepower to hole area

HSI = 1.2732 x Hb

Dh2

where: Hb = hydraulic horsepower at the bit, hp Dh = Hole Diameter, in


• Impact Force

= 0.0173 x Q x (Pb x )0.5

where: = impact force, lbfQ = flow rate, gal/minPb = pressure drop at bit, psi

= mud weight, ppg

Pbit = Q2

12031xAt2

where: = fluid density (ppg)Q = flow rate (gal/min)

At = total nozzle cross-sectional area “TFA” (in2)N = Nozzle size ( ie 12, 18, 20)

• Pressure Drop Across the Bit

At =

4 x 322x (N1

2 + N22 + …)


• Drilling 12-1/4” hole with 10.7 ppg WBM at 900 gpm, rock bit with 3 x 17/32 jets and 1 x 18/32 center jet. – What is the estimated pressure drop across the bit, HSI, and Impact Force?

1) Calculate bit TFA:

Bit Hydraulics Example #1

At =

4 x 322

x (172 + 172 + 172 + 182) = 0.9135 in2

2) Calculate bit pressure drop

10.7 x 9002

12031 x 0.91352Pbit = = 863 psi

3) Calculate HSI:


4) Calculate Impact Force

HHbb = = 863 x 900863 x 900

17141714= 453 hp= 453 hp

HSI = 1.2732 x 453

12.252= 3.84

= 0.0173 x 900 x (863 x 10.7)0.5 = 1,473 lbf


• Drilling 12-1/4” hole with 10.7 ppg WBM at 900 gpm, rock bit with 3 jets and 1 center jet. Drilling Engineer ask for an HSI of 4.0 – What are the appropriate nozzle sizes for the bit?

1) Calculate bit Hydraulic Horsepower:

Hb = HSI x Dh

2

1.2732

HHbb = = 4.0 x 12.254.0 x 12.2522

1.27321.2732= 471 HP= 471 HP


2) Calculate the bit Pressure Drop:

Pb = Hb x 1714

Q=

471 x 1714900

= 897 psi

3) Calculate the bit TFA:

TFA = x Q2

12031 x Pb

= 10.7 x 9002

12031 x 897= 0.803 in2


4) Calculate the bit Pressure Drop:4) Calculate the bit Pressure Drop:

AAtt = =

4 x 324 x 3222

x (Nx (N112 2 + N+ N22

22 + + ……))

Answer: Trial and error with available nozzles

One option: 2 x 15, 1 x 16, 1 x 18

Calculating Pressure Losses

• Mud properties– density– rheology

• Dimensions of drill string (+ tool joints) and casing components

• Flow rate and flow regime (laminar or turbulent)• Downhole equipment specifications

– bit nozzle sizes and number– downhole tools (mud motors, MWD, etc.)

• Dimensions of surface piping

Pipe and Annulus Pressure Losses

• Frictional pressure losses are calculated assuming:

– axial pipe flow through drill pipe and collars

– axial concentric flow through annulus (slot flow approximation)

• If the flow is laminar, the standard rheological models (Newtonian, Bingham Plastic, Power Law, etc.) can be used to calculate frictional pressure losses

• If the flow is turbulent, an empirical friction factor can be used to calculate frictional pressure losses

Reynolds Number

Flow of Newtonian fluids (oil-field units):

Re = 928 D v

379 Q

D =

where: = fluid density (ppg)v = average velocity (ft/sec)Q = flow rate (gal/min)D = pipe diameter (in) = fluid viscosity (cP)

Re = 757 (D2-D1) v

Pipe Flow

Annular Flow

Flow Regime for Newtonian Fluids

• For Re < 2100, flow is laminar

• For Re > 4000, flow is turbulent

• For 2100 < Re < 4000, flow is transitional (usually assumed turbulent)

Laminar Transitional Turbulent

Fanning Friction Factor

Empirical method to account for turbulence and calculate friction pressure losses in pipe and annular flows with Newtonian fluids

Includes:– surface roughness– laminar / turbulent flow

Applicable to:– pipe flow:

p/L = f v2 / 25.8 D

– annular flow:p/L = f v2 / 21.1(D2-D1)

Annulus: Laminar

Drill Pipe: Turbulent

Around BHA: Transitional

• Flow through the Drill Pipe is generally in Turbulent Flow (i.e. 4,000 < Re)

• Flow around BHA is generally Transitional (i.e. 2100 < Re < 4000), but can considered Turbulent

• Flow around Drill Pipe (annulus) is generally in Laminar Flow (i.e. Re < 2100)

Pipe and Annulus Pressure Losses

• The pressure drop through a circular pipe can be calculated from the following general equation.

Pressure Loss Equation for DP

P = 0.00001 x L x Cpb x x Vf x Q1.86

Where: P = pressure loss, psi L = length of pipe or collars, ft

= mud weight, ppg Vf = viscosity correction factor, (PV / )0.14

PV = plastic viscosity, centipose Q = flow rate, gal/min Cpb = coefficient through bore of pipe and

tool joints

• The pressure calculation needs to take into account both the tube ID and tool joint ID.

Pressure Loss Equation for DP

Where: Cpb = coef. through bore of tube and TJ Dpb = ID of tube, in Djb = ID of tool joint, in

Cpb = 5.68

Dpb 4.86

0.41

Djb 4.86+

• Coefficient for the Bore of the Collars

Ccb = 7.28

Dcb 4.86

Where: Ccb = coef. through bore of collars Dcb = ID of collar, in

• The pressure drop in the annulus pipe can be calculated from the following general equation.

Pressure Loss Equation for Annulus

P = 0.00001 x L x Cpa x x Vf x Q1.86

Where: P = pressure loss, psi L = length of pipe or collars, ft = mud weight, ppg

Vf = viscosity correction factor, (PV / )0.14 PV = plastic viscosity, centipose Q = flow rate, gal/min

Cpa = coef. For the annulus of the pipe

• The pressure calculation needs to take into account both the tube OD and tool joint OD.


Where: Cpa = coef. For the annulus of the pipe Dh = hole diameter, in Dp = OD of tube, in Dj = OD of the tool joint, in B = Parameter that takes into account

geometry and friction in the annulus

Cpa = 8.17 x B

(Dh - Dp) x (Dh2 - Dp

2)2+

0.43 x B

(Dh - Dj) x (Dh2 - Dj

2)2

Hole Diameter B Parameter4-3/4" and less 2.05-7/8" - 6-3/4" 2.27-3/8" - 7-3/4" 2.37-7/8" - 11" 2.412" and greater 2.5


• Coefficient for Annulus around Collars

Where: Cca = coef. for annulus of collar Dh = diameter of hole, in Dc = OD of collar, in

CCcaca = = 8.6 8.6 x B B

(D(Dhh - D - Dcc) x (D) x (Dhh22 - D - Dcc

22))22

Other Sources of Pressure Loss

• Surface Equipment– Stand pipe– Hose– Top Drive / Kelly / Swivel

• Motors / Turbine– Manufacture's data book– Operating parameters– Stalling

• MWD / LWD– Manufacture's data book– Positive pulse / negative pulse– Pump noise

Other Sources of Pressure Loss

Mud Pump / Standpipe Pressures

SPP =

Psurface piping

+ Pdrill pipe, collars, tool joints

+ Pdownhole tools

+ Pbit

+ Pannulus

• Standpipe pressure (SPP) is the total pressure required to circulate the mud down the drill string, through the bit, and back to the surface

Frictional Pressure Loss Equations

• Inaccuracies in frictional pressure loss calculations may result from neglecting:– downhole temperatures– downhole pressures– cuttings– tool joints– drill string rotation– hole washouts– drill string eccentricity– Mud type / properties

Important to know what the fluid service company is including in your hydraulics analysis

Hydraulics Example

• Estimate the SPP for the following hole section:– Drilling 12.25” from 5500’ MD to 10780’ MD– 13-3/8” 72# set at 5500’ MD– Flowrate: 800 gpm– Mud properties: MW - 10.7 ppg, PV = 25 cp– DP: 10,000’, 5-1/2”, 21.9#, 5-1/2” HT55 connection– HW: 600’, 5-1/2”, 57#, 5-1/2” FH connection– DC: 90’, 8”, 160#, 6-5/8” Regular connection– Motor pressure drop: 300 psi– LWD/MWD pressure drop: 300 psi– Bit pressure drop: 500 psi– Surface equipment pressure drop: 30 psi

Hydraulics Example

1) Calculate the pressure drop through the drill pipe:

Cpb = 5.68

Dpb 4.86

0.41

Djb 4.86+

Cpb = 5.68

4.778 4.86

0.41

3.875 4.86+ = 0.003407

P = 0.00001 x L x Cpb x x Vf x Q1.86

P = 0.00001 x 10000 x 0.003407 x 10.7 x 1.126 x 8001.86

P = 1030 psi

Hydraulics Example

2) Calculate the pressure drop through the heavy weight:

Cpb = 5.68

Dpb 4.86

0.41

Djb 4.86+

Cpb = 5.68

3.375 4.86

0.41

3.5 4.86+ = 0.01631

P = 0.00001 x L x Cpb x x Vf x Q1.86

P = 0.00001 x 600 x 0.01631 x 10.7 x 1.126 x 8001.86

P = 296 psi

Hydraulics Example

3) Calculate the pressure drop through the collars:

P = 0.00001 x L x Ccb x x Vf x Q1.86

P = 0.00001 x 90 x 0.25068 x 10.7 x 1.126 x 8001.86

P = 682 psi

Ccb = 7.28

Dcb 4.86 =7.28

2.0 4.86 = 0.25068

Hydraulics Example

4) Calculate the total pressure drop through the drill string and surface equipment:

P = Psurface piping + PDP, HW, DC, + PDH tools + Pbit

P = 30 + 2008 + 600 + 500

P = 3138 psi

Hydraulics Example

5) Calculate the pressure drop around the drill pipe x 13-3/8” annulus:

Cpa = 8.17 x B

(Dh - Dp) x (Dh2 - Dp

2)2+

0.43 x B

(Dh - Dj) x (Dh2 - Dj

2)2

Cpa = 8.17 x 2.5

(12.347 - 5.5)(12.3472 - 5.52)2+

0.43 x 2.5

(12.347 - 7.125) (12.3472 - 7.1252)2Cpa = 2.1968 x 10-4

P = 0.00001 x 5500 x 2.1968 x 10-4 x 10.7 x 1.126 x 8001.86

P = 36 psi

Hydraulics Example

6) Calculate the pressure drop around the drill pipe x 12-1/4” annulus:

Cpa = 8.17 x 2.5

(12.25 - 5.5)(12.252 - 5.52)2+

0.43 x 2.5

(12.25 - 7.125) (12.252 - 7.1252)2Cpa = 2.3207 x 10-4

P = 0.00001 x 4500 x 2.3206 x 10-4 x 10.7 x 1.126 x 8001.86

P = 32 psi

Hydraulics Example

7) Calculate the pressure drop around the heavy weight x 12-1/4” annulus:

Cpa = 8.17 x 2.5

(12.25 - 5.5)(12.252 - 5.52)2+

0.43 x 2.5

(12.25 - 7.0) (12.252 - 7.02)2

Cpa = 2.3084 x 10-4

P = 0.00001 x 600 x 2.3206 x 10-4 x 10.7 x 1.126 x 8001.86

P = 4 psi

Hydraulics Example

8) Calculate the pressure drop around the collars x 12-1/4” annulus:

Cpa = 8.2357 x 10-4

P = 0.00001 x 90 x 8.2357 x 10-4 x 10.7 x 1.126 x 8001.86

P = 2 psi

Cca = 8.6 x B

(Dh - Dc) x (Dh2 - Dc

2)2=

8.6 x 2.5

(12.5 - 8) x (12.252 - 82)2

Hydraulics Example

9) Calculate the total pressure drop in the annulus and the ECD:

P = PDP x 13-3/8” csg + PDP x OH + PHW x OH + PDC x OH

P = 36 + 32 + 4 + 2 = 74 psi

ECD = MW +Pannulus

0.052 TVD

ECD = 10.7 +74

0.052 10800 = 10.8 ppg

Hydraulics Example

10) Calculate the SPP:

SSP = Psurf. Equip + PDP, HW, DC,+ PDH tools + Pbit + Pannulus

SSP = 30 + 2008 + 600 + 500 + 74 = 3212 psi

• How large are typical ECDs and SPPs?

• If SPP is design limitation, what are the options?

• If ECD is design limitation, what are the options?

• What are typical temperature and pressure effects in deepwater?

• What are typical drill string rotation effects?

• What are typical cuttings effects?

Hydraulics Related Design Issues

Where Do Most Frictional Pressure Losses Occur?

S A 2 12 1/4" 21500' M D 962 gpm Delta P

A nnulus

B it

Tools

Drill S tring

S A 2 8 1 /2 " 2 2 2 9 5 ' M D 4 3 9 g p m D e lta P

A n n u lu s

B it

To o ls

D ril l S t rin g

S A 2 8 1 / 2 " 2 2 2 9 5 ' M D 4 3 9 g p m D e l t a P

A n n u lu s

B i t

T o o ls

D r i l l S t r in g

Typical 12-1/4” Hole Typical 8-1/2” Hole

• Reduce pressure drop in drill string– larger size drill pipe– tapered drill string– lower PV

• Reduce pressure drop in tools– motor– MWD tools

• Reduce pressure drop across bit• Increase SPP limit

Options for SPP Limitations

TypicalClass 1 Rig

TypicalClass 2 Rig

Maximum SPP Limit 5000 psi 7000 psi

Working SPP Limit 4000-4500 psi 5600-6300 psi

All highlydependent onflow rate andmud rheology(hole cleaningrequirements)

• Reduce pressure drop in annulus– smaller size drill pipe, high torque tool joints– larger casing / hole size– lower flow rate and mud rheology (YP)– must consider hole cleaning requirements

• Decrease mud weight– must consider wellbore stability requirements

Options for ECD Limitations

Situations Where Hydraulics is Often a Concern

• Long MD wells• Narrow margin between pore pressure and fracture

gradient (deepwater)• Long, tight liners• Low-clearance casing designs• Slim hole well designs• Large hole sections with small drill pipe

Surge and Swab

Pipe movement causes flow in annulus and results in increase or decrease in wellbore pressure

downward movementpressure increase - surge

upward movementpressure decrease- swab

• Can cause lost returns and well control problems

• Swab can induce wellbore instability -particularly below BHA pack-offs

• Determine maximum speeds for running casing / liners and reciprocating during cementing

• Determine maximum speeds for running pipe

• Surge and swab depend on: – wellbore ID, pipe OD / ID – well depth, profile, & temperature– cuttings in flow stream and beds

Significance of Surge and Swab

– mud properties– pipe running speed– open area of pipe end

Breaking Circulation

• If circulation has not been broken > 1 hr, rotate pipe (10-20 rpm) before starting pumps

• Start pumps at as low a rate as possible and build up to drilling flow rate - monitor PWD if available

• After breaking circulation, bring pumps up to the drilling rate for a short period - 5 min

• Do not run down and break circulation at the same time

Using PWD Data

• Monitor pressure and ECD while drilling

• Monitor cuttings beds formation and determine when to circulate (with torque and drag/ECD)

• Monitor pressure while circulating (vs time) to determine when equilibrium is achieved

• Warning system during backreaming operations (requires increased sample rate ~15 sec)

While Drilling

Using PWD Data

• Relate ECDs to different well conditions (rotating, sliding, tripping, breaking circulation, etc.) to improve future well planning

• Validate hydraulics programs used for well planning

After Drilling

How to Collect PWD Data

• Set up systems that allow easy monitoring

• Effectively communicate information to the driller in a timely manner

• Increase sampling rate if data are used for backreaming operations

• Collect depth-based data on a compressed scale to easily identify trends while drilling

• Collect time-based data to relate to actual well conditions after drilling

Lesson Summary

• Wellbore hydraulics requires knowledge of frictional Wellbore hydraulics requires knowledge of frictional pressure losses during circulating and tripping pressure losses during circulating and tripping operations for the complete circulating systemoperations for the complete circulating system

• Wellbore hydraulics may be highly dependent on Wellbore hydraulics may be highly dependent on downhole conditionsdownhole conditions

• When designing a drilling program, many tradeoffs When designing a drilling program, many tradeoffs must be considered between hydraulics (ECD and must be considered between hydraulics (ECD and SPP), hole cleaning, and wellbore stabilitySPP), hole cleaning, and wellbore stability

• PWD data may supply valuable information related to PWD data may supply valuable information related to hydraulics and hole cleaning while drilling and for hydraulics and hole cleaning while drilling and for future well planningfuture well planning

What Can You Do!

• Ensure pumps and operating parts are in good condition (liners free from corrosion, pistons in good shape) and being given proper maintenance.

• Check nozzle sizes in bits when they are delivered and make sure extras are on the rig (2 size larger and smaller than required).

• Ensure standpipe manifold is in good condition and make sure all gauges / valves are working.

• Learn the pipe layout on the rig.• Perform efficiency test on pumps when possible.• Does the rig contractor have adequate spare parts and

sufficient inventory of liner sizes and pistons.

What Can You Do!

• Are the circulating / hydraulic parameters listed in the drilling program.

• Double check the engineers hydraulic calculations.• Calibrate the estimated system pressure loss with the

actual pump pressure and report if there is a large variance.

• If a PWD is ran in the string, use data to determine surge / swab, ECD deference's between circulating and rotating, and equivalent static bottom hole density.