ATMATM PETE 689 UBD ATMATM ATMATMATMATM Lesson 12 Well Engineering

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Lesson 12

Well Engineering

Harold Vance Department of Petroleum Engineering

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Well Engineering

• Circulation Programs

• Circulation Calculations (air, gas, mist)

• Circulation Calculations (gasified liquids)


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Well Engineering

• Wellhead Design

• Casing Design

• Completion Design


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Well Engineering

• Bit selection

• Underbalanced perforating

• Drillstring design

• Separator design


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Hole Cleaning

• Optimizing hydraulics with gasses is primarily concerned with hole cleaning - getting the cuttings that are generated by the bit out of the hole.

• With gas, rheological properties have very little to do with hole cleaning

• Hole cleaning with gasses is almost entirely dependent on the annular velocity


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Drag and Gravitational Forces

• Flowing air exerts a drag force on cuttings

• Gravitational force on the cuttings

• Therefore there is a threshold velocity in which the cuttings will be lifted from the wellbore.

• Threshold velocity increases with size of cuttings.


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Hole cleaning

• Compressibility of air (or gas) complicates matters.

• Frictional pressure increases downhole pressure - decreases velocity downhole

• Suspended cuttings increase the density of the air, increasing downhole pressure.

• Temperature has an effect on volumetric flow rate.


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Hole Cleaning

• We must pump at a velocity high enough to remove the cuttings, but not too high where we waste energy.


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Hole Cleaning Criteria

• Terminal Velocity Criteria

• Minimum Energy Criteria

• Minimum BHP Criteria


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Terminal Velocity Criteria

• Gray determined that the minimum velocity of the gas must be at least as high as the terminal velocity of the cutting in order to lift the cutting from the wellbore.

• Vc = Vf - Vt


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Terminal velocity

3f

3c

d

c

2

lbm/ft fluid, ofdensity ρ

lbm/ft cuttings, ofdensity ρ

tcoefficien dragC

ft. diameter, particle sticcharacterid

ft/sec 32.17 on,accelerati nalgravitatio g

34

fd

fcct C

gdV


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Terminal Velocity

psia and Rin

conditions hole bottomat are P and T

cuttings round-subfor

164.4

cuttingsflat for

369.3

P

TdV

P

TdV

cct

cct


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Terminal Velocity

• Terminal velocity in air drilling is determined mainly by:– cutting diameter, shape, and density– bottom hole temperature and pressure


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Terminal Velocity

• As pressure increases Vt decreases.

• As pressure increases Air velocity decreases

• If the mass flow rate of gas remains constant the local air velocity decreases with increasing pressure.

• The air flow rate required to lift the cuttings increases with increasing BHP


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Friction Pressure

ft diameter, pipeD

ft diameter, holeD

gravity todueon acceleratig

ft/s velocity,mixturev

lbm/cu.ft density, mixtureρ

cuttings andair of

mixture theoffactor friction f

2

p

h

m

m

m

2

ph

mmmm DDg

vf

dL

dP Eq. 2.5


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Friction Pressure

pipe theof roughness absoluteε

2ln86.014.1

f

1

correct more is Nikuradse that argued Guo

14.0

quationWeymouth

f

a

333.0

m

ph

ph

a

ca

DD

DDf

ff


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Friction Pressure

• Mixture density is a function of air density, cuttings density, and mass of the cuttings.

• Air density is a function of the pressure

• Mass of the cuttings is a function of:– ROP– Hole cleaning efficiency


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Friction Pressure

• Pressure drops down the drillstring and through the bit play a part in BHP due to temperature effects.

• Temperature is also effected by:– formation temperature– influx of formation fluid (expansion of gas into the

wellbore)– Mechanical friction– Pressure


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Required injection rates???

• Relating downhole air velocities to surface injection rates is quite complex.

• We need cuttings shape and size to determine terminal velocity


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Minimum Energy Criteria

• Probably the most widely used criteria was developed by Angel in 1957.

• Angel assumed that, for efficient cuttings transport downhole, the kinetic energy of the air striking each cutting should be the same as that of air giving efficient cuttings transport at standard pressure and temperature.


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ft/min pressure, and Temp standard

atvelocity air(orgas)v

lbm/cuft pressure, and tempstandard

at gas)(or air ofdensity ρ

ft/min downhole, velocity gas)(or air v

lbm/cuft rate,injection

downhole required minimum

at the gas)(or air ofdensity ρ2

1

2

1

stp

stp

min

min

22minmin

stpstpvv


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minmin

stpstpvv


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• Experience from shallow blast holes, drilled in limestone quarrying operations, indicated that cuttings were transported efficiently if the air velocity equaled or exceeded 3,000 feet per minute.

• This is equivalent to Gray’s terminal velocity for flat cuttings with a diameter of 0.46 in. or sub-rounded particles of 0.26 in.


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lbm/min air, of rate flow mass

the;given time ain wellin the

pointany past flowingair of massw

lbm/min cuttings,

of rate flow mass the;given time

ain generated cuttings of massw

1

2

a

c

2

a

cam

ph

mmmm

w

w

DDg

vf

dL

dP

Angel computed the downhole air pressure with eq. 2.5


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depth holeh

GhTre temperatudownholeT

F/100' gradient, mperatureannular teG

F re, temperatusurfaceT

absolute lbf/sq.ft, pressure,air surfaceP

s

s

s

22

22

aG

abT

T

T

aG

abTPP

G

a

s

ssb


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ft. diameter, drillpipeD

ft. diameter, holeD

101.625b

ft/hr rate,n penetratioROP

scf/m rate, flow gasQ

1)(airgravity specific gasS

3.53

8.28

p

h

222333.1

26-

2

phph

h

DDDD

Q

Q

DROPSQa


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This was combined with the cuttings transport criterion defined in Eq 2.10 to deduce the minimum air flow rate as a function of hole depth, annular geometry, and penetration rate.

minmin

stpstpvv Eq. 2.10


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To simplify, the average downhole temperature can be used to calculate BHP.

2222

2222

261.6av

Tahavs

stpph

s bTebTPvDD

QGhTSav

This was solved numerically for the gas injection rate required to give an annular velocity equivalent in cuttings lifting power to air with a velocity of 3000 ft/min.

A series of charts was generated for different geometries and penetration rates


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• Qmin can be approximated by:

• Qmin = Qo + NH

• Qo = injection rate (scfm) at zero depth that corresponds to an annular velocity of 3000 ft/min

• N = factor dependent on the penetration rate (Appendix C)

• H = hole depth, 1000 ft.


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7-7/8” hole 3-1/2” drillpipe

6” drill collars 3800’ hole depth


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Minimum BHP Criteria

Angel’ analysis does not predict a minimum BHP, but gives a pressure that decreases monotonically with decreasing air flow rate.


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Natural Gas Drilling

3f

3c

d

c

2

lbm/ft fluid, ofdensity ρ

lbm/ft cuttings, ofdensity ρ

tcoefficien dragC

ft. diameter, particle sticcharacterid

ft/sec 32.17 on,accelerati nalgravitatio g

34

fd

fcct C

gdV


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Terminal velocity of natural gas

• Vtg = Vtair(1/S)0.5


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Natural gas drilling

• Lower density of natural gas than air results in:– lower BHP– lower drag forces– Higher required circulation rates– Non-ideal behavior of natural gas is not usually

a problem since operating pressures are low and ideal behavior can be assumed.


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Natural gas injection rate

• A first order estimate can be derived by taking Angel’s figures for air drilling at the appropriate depth and penetration rate and dividing these by the square root of the gas’s specific gravity.

• Usually acceptable in practice


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Mist Drilling

• Liquid volumes are only 1 to 2 percent at the prevailing temperature and pressure.


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Hole cleaning, mist

• Water droplets act similarly to cuttings with slip velocity of near zero - mists do not clean the wellbore more efficiently than dry gas. Therefore annular velocities are high.

• Circulating fluid density is increased however and may add to the frictional pressure losses.


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Hole cleaning, mist

• The increased density will lower the terminal velocity of the cuttings, but will increase the BHP reducing the volumetric flow rate at the bottom of the hole.

• Higher air injection rates are usually required when misting than with dry air.


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Application of Angel’s method to mist drilling

• Determine the penetration rate that would generate the same mass of cuttings as the mass of liquid entering the well over a time period. This includes any base liquid, foamer, and water influx.


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Apparent equivalent ROP

rate.n penetratio

danticipate actual the toadded is This

380

124169

350.5L

lbm/ft.cu. 62.4 is water ofdensity the

assuming 350.5L is rate flow mass the

(BPH) L is rate liquid total theIf

22bb

e D

L

DROP


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Angel’s method for mist

• The minimum air injection rate, required for good hole cleaning during mist drilling, is determined; either from Angel’s charts or from the approximation in equation 2.17


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Example

• Hole size = 7 7/8”

• depth = 5000’

• Drillpipe size = 4 1/2”

• Anticipated ROP = 30 feet/hr

• Qo = 671, N = 65, H = 5000/1000 = 5

• Minimum air rate for dry air =

• Qa = Qa +NH = 670 + 65x5 = 995 scfm


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Example

• Liquid injection rate is 6 BPH

• Water influx is 3.8 BPH

• Total liquid rate is 9.8 BPH

• Penetration rate that would give this mass cuttings per hour is 60 ft/hr.


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Example

• The minimum air rate required for dry air drilling at a penetration rate of 90 ft/hr using the value of N for 90 ft/hr, N = 98.3 would be 1162 scfm


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Wellhead Design - Low pressure

• Gas, mist, and foam drilling are normally utilized on low pressure wells

• Low pressure wells require simple wellhead designs

• Some operators opt for a simple annular preventer alone


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• However, a principal manufacturer of such equipment strongly cautions that such use exceeds the design criteria of this equipment.

• The minimum setup should consist of a rotating head mounted above a two ram set of manually-operated blowout preventers, consisting of a pipe ram and a blind ram


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• Slightly higher pressure systems should also have an annular preventer between the rams and the rotating head.

• For added safety the BOP system should be hydraulically operated

• Working pressure of these rotating heads is ~400-500 psi


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Wellhead Design - High pressure

• Gasified liquids, flowdrilling, mudcap drilling

• Rotating heads on top of conventional hydraulically operated BOP usually suffice

• In Canada, nitrified liquids are often used with an RBOP installed atop a conventional BOP stack.


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• Blind rams should be installed in the bottom set of rams (when a two ram system is used)

• Sometimes a third set of rams (pipe rams) is utilized.

• In this case the RBOP is installed atop an annular preventer.

• The blind ram is placed between the two sets of pipe rams.


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• The lowermost set of rams should be installed directly atop the wellhead (or an adapter spool if necessary)

• You should never place any choke or kill lines below the lowest set of rams.

• If one of these lines cuts out, there is no way to shut in the well.


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• Care must be taken to utilize a rig with a substructure high enough so that the wellhead is not below ground level, with space enough to put the entire desired BOP stack below the rig floor


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Wellhead Design - Snub drilling

• Snub drilling and CT drilling have BOP stacks that allow tripping at much higher pressures than other forms of UBD (routinely up to 10,000 psi)

• Snubbing and CT units can be used for UBD at pressure that cannot be managed by conventional surface equipment.


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Casing Design

• Casing design for UBD is not significantly different than conventional

• With air drilling, the casing tension should always be design with no buoyancy considered.

• No difference in burst design - usually


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Casing Design

• Collapse design should always be based on an empty casing string

• A collapse design factor for UBD should be ~1.2 for UBD instead of 1.125 (API design factor)


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Casing Design - Corrosion control

• For fluid filled wells, corrosion is usually not considered when drilling.

• Corrosion is not a factor when drilling with dry air

• Corrosion must be considered when drilling with mist, foam, or aerated fluids.

• Corrosion inhibitors should be added to the system


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Casing Design - Casing wear

• Casing wear is accelerated with gas drilling

• This is due to less lubrication by the drilling fluid

• Most air drilled holes are drilled faster and less time is spent rotating

• Doglegs add to casing wear


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Completion Design

• If a well is properly drilled under underbalanced conditions, but is completed using overbalanced methods, much if not all of the impairment-reducing benefits might be permanently lost.


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Underbalanced Completion Techniques

• Running production casing, liners, slotted liners and other tools underbalanced.

• Controlled cementing of production casing or liners

• Running production tubing and downhole completion assemblies

• Perforating underbalanced


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Running casing and liners underbalanced

• If the completion is not open hole, casing or liners must be run

• Surface pressures are usually reduced by bullheading a heavier fluid down the annulus.

• This fluid may be more dense than that with which the well was drilled, but still must be light enough to prevent overbalance.


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• For casing and un-slotted liners, the well is usually allowed to flow while running the casing.

• This helps to prevent excessive surge pressures.

• A snubbing unit might be required to get the casing started in the hole.


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• Slotted liners do not allow the well to be shut-in when the liner is across the BOP stack.

• It may be necessary to flood the backside with drilling fluid to allow the running of the slotted liner into the wellbore

• Fluid is continuously pumped down the wellbore to reduce pressures


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Cementing pipe underbalanced

• If casing is run underbalanced, cementing should also be accomplished underbalanced.

• HSP of the cement slurry can be reduced by entraining gas, or by reduced density additives.


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Running tubing underbalanced

• No matter the production casing/liner design, production will almost always be required.

• With cemented casing and liners, the tubing can be run conventionally.


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Running tubing underbalanced

• Tubing can be run underbalanced in a number of ways– snubbing– CT– diverting flow– Setting a packer above the open zone with a

temporary plug


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Bit selection

• The bit selection process– Assemble offset well data– Develop a description of the well to be drilled– Review offset well bit runs– Develop candidate bit programs– Confirm that the selected bits are consistent with

the proposed BHA’s– Perform an economic evaluation, to identify the

preferred bit program


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Assemble offset well data

• Identify the nearest, most similar wells to the proposed location

• Gather as much information as possible about drilling these wells

• Include bit records, mud logs, wireline logs, daily drilling reports, mud reports, directional reports


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Develop a description of the well to be drilled

• Characterize the proposed hole geometry– hole size– casing points,– trajectory


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• Outline the anticipated values of rock hardness and abrasivity at all depths– Sonic travel time logs give qualitative

indications of formation hardness.• Low travel times - high rock compressive strengths


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• Outline the anticipated values of rock hardness and abrasivity at all depths– Abrasivity is more difficult to quantify

• It is possible to form a qualitative assessment of the rock’s potential for abrasive bit wear.

• Abrasiveness is related to– Hardness of its constituent minerals– Bulk compressive strength– Grain size distribution– Shape


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• Make note of any formations that may have a special impact on bit performance

• Divide the well into distinct zones

• Each zone corresponds to a significant change in formation properties or drilling condition


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Review offset well bit runs

• Determine what bits were used to drill through each formation likely to be penetrated

• Identify which bit gave the best or worst performance

• Look at the bit grading

• Use the bit performance to infer formation hardness and abrasivity


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Identify candidate bits

• Identify which bits are candidates for each zone to be penetrated

• Consider fixed cutter and roller cone bits


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Roller Cone Bits

• Key design considerations for roller cone bits are:– cutting structure– bearing– seal types– gauge protection

• Should be matched to the formations hardness and abrasivity


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Fixed Cutter Bits

• Key design considerations for fixed cutter bits are:– cutting structure– body material and profile– gauge– stabilizing (anti-whirl) features

• Should be matched to formations hardness and abrasivity


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Fixed Cutter considerations

• PCD cutters wear rapidly in hard formations

• Impregnated and natural diamond bits tolerate very hard and abrasive formations

• Gauge protection is dependent on abrasiveness


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Develop candidate bit programs

• At this stage, develop several alternative bit programs.

• Consists of type of bit, start and end depths, and anticipated penetration rates.


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Confirm that the selected bits are consistent with the proposed

BHA’s

• Do the operating parameters of the proposed BHA’s inhibit bit performance?

• Is WOB limited?

• Do the selected downhole motors exceed the rpm capabilities of the bits?


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Perform an economic evaluation, to identify the preferred bit

program• Use the estimated penetration rate and bit life

to predict the probable cost for each bit run:

• Chi = CriTi + Cbi

• Predicted cost of the interval is the sum of all the bit costs for the particular bit program.

• Rank all the alternative bit programs


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Bit selection for Dry Gas, Must and Foam drilling

• Roller cone

• Fixed cutter


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Roller Cone Bits

• Dry gas drilling produces a smoother hole bottom than with mud, and full coverage of the bottom of the hole with cutters is not as important.

• Larger teeth can be used for harder formations

• Abrasive wear is normally higher for dry gas drilling


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Roller Cone Bits

• Cone offset is not as important with dry gas drilling

• Good gauge protection is very important

• Utilize sealed bearings


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Fixed Cutter Bits

• PDC bits are usually a poor choice for dry gas drilling

• Not has heat tolerant

• Diamond bits may be heat tolerant.


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Bit selection for gasified and liquid systems

• Not much difference from conventional drilling


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Underbalanced perforating

• Can be performed with wireline or with tubing conveyed perforating guns.


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Drillstring design

• Similar to conventional drilling

• There will be less buoyancy

• BHA should be designed so that all compression is in the BHA

• An exception is in horizontal wellbores.


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Example 6


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Example 6


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Example 6


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Example 6


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Drillstring design

• Drillpipe is usually designed with:– a design factor of 1.1– and an overpull from 50,000 - 100,000 lbf


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Example 7


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Example 7


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Example 7


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Example 7


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Example 7


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Separator designCapacity is a function of:

• Size

• Design and arrangement

• Number of stages

• Operating P and T

• Characteristics of fluids

• Varying gas/liquid ratio

• Size and distribution of particles

• Liquid level

• Well-fluid pattern

• Foreign material in fluids

• Foaming tendency of fluids

• Physical condition of separator

• Others


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Maximum gas velocity


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Gas Separating Capacity


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ATMATM PETE 689 UBD ATMATM ATMATMATMATM Lesson 12 Well Engineering