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### Lesson 12 Well Engineering Well Engineering Circulation Programs Circulation Calculations (air, gas, mist) Circulation Calculations (gasified liquids) Well ... – PowerPoint PPT presentation

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Title: Well Engineering

1
Lesson 12
• Well Engineering

2
Well Engineering
• Circulation Programs
• Circulation Calculations (air, gas, mist)
• Circulation Calculations (gasified liquids)

3
Well Engineering
• Casing Design
• Completion Design

4
Well Engineering
• Bit selection
• Underbalanced perforating
• Drillstring design
• Separator design

5
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

6
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.

7
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.

8
Hole Cleaning
• We must pump at a velocity high enough to remove
the cuttings, but not too high where we waste
energy.

9
Hole Cleaning Criteria
• Terminal Velocity Criteria
• Minimum Energy Criteria
• Minimum BHP Criteria

10
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

11
Terminal velocity
12
Terminal Velocity
13
Terminal Velocity
• Terminal velocity in air drilling is determined
mainly by
• cutting diameter, shape, and density
• bottom hole temperature and pressure

14
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

15
Friction Pressure
Eq. 2.5
16
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

18
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

19
Required injection rates???
• Relating downhole air velocities to surface
injection rates is quite complex.
• We need cuttings shape and size to determine
terminal velocity

20
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.

21
Minimum Energy Criteria
22
Minimum Energy Criteria
23
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.

24
Minimum Energy Criteria
Angel computed the downhole air pressure with eq.
2.5
25
Minimum Energy Criteria
26
Minimum Energy Criteria
27
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
28
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
29
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.

30
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32
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33
7-7/8 hole 3-1/2 drillpipe 6 drill
collars 3800 hole depth
34
Minimum BHP Criteria
Angel analysis does not predict a minimum BHP,
but gives a pressure that decreases monotonically
with decreasing air flow rate.
35
Natural Gas Drilling
36
Terminal velocity of natural gas
• Vtg Vtair(1/S)0.5

37
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.

38
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.

40
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.

41
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.

42
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.

43
Apparent equivalent ROP
44
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

45
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

46
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.

47
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

48
• 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

49
• 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

50
• Slightly higher pressure systems should also have
an annular preventer between the rams and the
• For added safety the BOP system should be
hydraulically operated
• Working pressure of these rotating heads is
400-500 psi

51
• 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.

52
• 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.

53
• The lowermost set of rams should be installed
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.

54
• 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

55
• 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.

56
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

57
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)

58
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

59
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

60
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.

61
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

62
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.

63
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.

64
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

65
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.

66
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.

67
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

68
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

69
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

70
Develop a description of the well to be drilled
• Characterize the proposed hole geometry
• hole size
• casing points,
• trajectory

71
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

72
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

73
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

74
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

75
Identify candidate bits
• Identify which bits are candidates for each zone
to be penetrated
• Consider fixed cutter and roller cone bits

76
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

77
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

78
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

79
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.

80
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?

81
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

82
Bit selection for Dry Gas, Must and Foam drilling
• Roller cone
• Fixed cutter

83
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

84
Roller Cone Bits
• Cone offset is not as important with dry gas
drilling
• Good gauge protection is very important
• Utilize sealed bearings

85
Fixed Cutter Bits
• PDC bits are usually a poor choice for dry gas
drilling
• Not has heat tolerant
• Diamond bits may be heat tolerant.

86
Bit selection for gasified and liquid systems
• Not much difference from conventional drilling

87
Underbalanced perforating
• Can be performed with wireline or with tubing
conveyed perforating guns.

88
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.

89
Example 6
90
Example 6
91
Example 6
92
Example 6
93
Drillstring design
• Drillpipe is usually designed with
• a design factor of 1.1
• and an overpull from 50,000 - 100,000 lbf

94
Example 7
95
Example 7
96
Example 7
97
Example 7
98
Example 7
99
Separator design Capacity 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

100
Maximum gas velocity
101
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102
Gas Separating Capacity
103
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104
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105
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106
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