Transcript Lesson 13 - University of Stavanger

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PETE 689 UBD
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Lesson 12
Well Engineering
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Well Engineering
• Circulation Programs
• Circulation Calculations (air, gas, mist)
• Circulation Calculations (gasified liquids)
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Harold Vance Department of
Petroleum Engineering
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Well Engineering
• Wellhead Design
• Casing Design
• Completion Design
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Well Engineering
•
•
•
•
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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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Petroleum Engineering
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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 = V f - Vt
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Terminal velocity
c   f
Vt  4 gdc
3Cd  f
g  gravitat ional acceleraton,
i 32.17ft /sec
2
d c  charact erist ic part iclediamet er,ft .
C d  drag coefficient
ρ c  density of cut t ings,lbm/ft
3
ρ f  density of fluid, lbm/ft3
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Terminal Velocity
d cT  c
Vt  3.369
P
for flat cut t ings
d cT  c
Vt  4.164
P
for sub - round cut t ings
T and P are at bot t omhole condit ions
in R and psia
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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
 f m  m vm2 
dP

 m  
 2 g D  D  
dL
h
p 

Eq. 2.5
f m  frictionfactorof themixt ure
of air and cuttings
ρ m  mixt uredensit y,lbm/cu.ft
v m  mixt urevelocity,ft /s
g  acceleraton
i due to gravit y
D h  holediameter,ft
D p  pipe diameter,ft
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Friction Pressure
fm  fa  fc
Weymouthquation
0.14
fa 
0.333
Dh  D p 
Guo argued that Nikuradse is morecorrect
 2 
1

 1.14  0.86 ln
D D 
fa
p 
 h
ε  absolute roughnessof thepipe
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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:
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– 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
1
1
2
2
 minvmin   stp vstp
2
2
ρ min  densit yof air (or gas) at the
minimumrequired downhole
injectionrate,lbm/cuft
v min  air (or gas) velocitydownhole,ft/min
ρ stp  densit yof air (or gas) at
standardtempand pressure,lbm/cuft
v stp  air(orgas)velocityat
standardT empand pressure,ft/min
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Minimum Energy Criteria
vmin  vstp
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 stp
 min
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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 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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Minimum Energy Criteria
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Angel computed the downhole air pressure with eq. 2.5
 f m  m vm2 
dP

 m  
 2 g D  D  
dL
h
p 

 wc 
 m   a 1  
 wa 
w c  mass of cuttingsgeneratedin a
given time; themass flow rateof
cuttings,lbm/min
w a  mass of air flowing past any point
in thewell in a given time; the
mass flow rateof air, lbm/min
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Minimum Energy Criteria
2a
G
 2 abTs2  T 
abT 2
  
Pb   Ps 
Ga
G  a  Ts 

Ps  surface air pressure,lbf/sq.ft,absolute
re, F
Ts  surface temperatu
G  annular temperaturegradient,F/100'
re  Ts  Gh
T  downhole temperatu
h  hole depth
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Minimum Energy Criteria
SQ  28.8  ROP  Dh2
a
53.3Q
S  gas specificgravity(air  1)
Q  gas flow rate,scf/m
ROP  penetration rate,ft/hr
b
D
h
1.625 10-6 Q 2
 Dp 
1.333
D
2
h
D

2 2
p
D h  hole diameter,ft.
D p  drillpipediameter,ft.
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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.
vmin  vstp
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 stp
 min
Eq. 2.10
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Minimum Energy Criteria
To simplify, the average downhole temperature can be used to
calculate BHP.
6.61S Ts  GhQ 2
D
2
h
D
v
2 2 2
p
stp

P
2
s

 bTav2 e 2 ah Tav  bTav2
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
c   f
Vt  4 gdc
3Cd  f
g  gravitat ional acceleraton,
i 32.17ft /sec
2
d c  charact erist ic part iclediamet er,ft .
C d  drag coefficient
ρ c  density of cut t ings,lbm/ft
3
ρ f  density of fluid, lbm/ft3
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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:
–
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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
If the tot alliquid rateis L (BP H)
the mass flow rateis 350.5Lassuming
thedensity of wat er is 62.4lbm/ft .cu.
350.5L
380L
ROPe 

2
2
D
   Db 
b
169  
 4  12 
T hisis added to theact ualanticipated
penetration rate.
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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
•
•
•
•
•
•
•
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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
•
•
•
•
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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
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–
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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
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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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Petroleum Engineering
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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
rock’s potential for abrasive bit wear.
• Abrasiveness is related to
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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
ATM
Harold Vance Department of
Petroleum Engineering
ATM
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PETE 689 UBD
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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
ATM
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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
ATM
Harold Vance Department of
Petroleum Engineering
ATM
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PETE 689 UBD
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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
ATM
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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
ATM
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Confirm that the selected bits are
consistent with the proposed
BHA’s
ATM
• 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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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Perform an economic evaluation,
to identify the preferred bit
program
ATM
• 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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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Bit selection for Dry Gas, Must
and Foam drilling
• Roller cone
• Fixed cutter
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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
ATM
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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.
ATM
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Bit selection for gasified and
liquid systems
• Not much difference from conventional
drilling
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Underbalanced perforating
• Can be performed with wireline or with
tubing conveyed perforating guns.
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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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.
ATM
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Example 6
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Petroleum Engineering
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Example 6
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Example 6
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Petroleum Engineering
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PETE 689 UBD
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Harold Vance Department of
Petroleum Engineering
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Example 6
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PETE 689 UBD
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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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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Example 7
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Petroleum Engineering
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PETE 689 UBD
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Example 7
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Example 7
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Example 7
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Example 7
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Separator design
Capacity is a function of:
•
•
•
•
•
•
•
ATM
Size
Design and arrangement
Number of stages
Operating P and T
Characteristics of fluids
Varying gas/liquid ratio
Size and distribution of
particles
ATM
•
•
•
•
Liquid level
Well-fluid pattern
Foreign material in fluids
Foaming tendency of
fluids
• Physical condition of
separator
• Others
Harold Vance Department of
Petroleum Engineering
ATM
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PETE 689 UBD
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Maximum gas velocity
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Harold Vance Department of
Petroleum Engineering
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Harold Vance Department of
Petroleum Engineering
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Gas Separating Capacity
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Harold Vance Department of
Petroleum Engineering
ATM
ATM
PETE 689 UBD
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Harold Vance Department of
Petroleum Engineering
ATM
ATM
PETE 689 UBD
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Harold Vance Department of
Petroleum Engineering
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