Well Engineering

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Lesson 12

• Well Engineering

2
Well Engineering

• Circulation Programs
• Circulation Calculations (air, gas, mist)
• Circulation Calculations (gasified liquids)

3
Well Engineering

• Wellhead Design
• Casing Design
• Completion Design

4
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
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Terminal Velocity
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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
Eq. 2.5
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Friction Pressure
17
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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Minimum Energy Criteria
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Minimum Energy Criteria
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Minimum Energy Criteria

• 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 Grays terminal velocity
  for flat cuttings with a diameter of 0.46 in. or
  sub-rounded particles of 0.26 in.

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Minimum Energy Criteria
Angel computed the downhole air pressure with eq.
2.5
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Minimum Energy Criteria
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Minimum Energy Criteria
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Minimum Energy Criteria
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.
Eq. 2.10
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Minimum Energy Criteria
To simplify, the average downhole temperature can
be used to calculate BHP.
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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Minimum Energy Criteria

• 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
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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
  Angels figures for air drilling at the
  appropriate depth and penetration rate and
  dividing these by the square root of the gass
  specific gravity.
• Usually acceptable in practice

39
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 Angels 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
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Angels method for mist

• The minimum air injection rate, required for good
  hole cleaning during mist drilling, is
  determined either from Angels 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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Wellhead Design - Low pressure

• 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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Wellhead Design - Low pressure

• 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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Wellhead Design - High pressure

• 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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Wellhead Design - High pressure

• 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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Wellhead Design - High pressure

• 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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Running casing and liners underbalanced

• 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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Running casing and liners underbalanced

• 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 BHAs
• 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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Develop a description of the well to be drilled

• 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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Develop a description of the well to be drilled

• 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 rocks 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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Develop a description of the well to be drilled

• 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 BHAs

• Do the operating parameters of the proposed BHAs
  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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