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Lesson10Flow Drilling Mudcap DrillingSnub Drilling
Closed SystemsRead: UDM Chapter 2.8-2.11
Pages 2.180-2.219
PETE 689Underbalanced Drilling (UBD)
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Flow Drilling
Flow drilling refers to drillingoperations in which the well isallowed to flow to surface whiledrilling.
All UBD operations are really flowdrilling operations, but the term is
usually applied to drilling with asingle phase mud, and no gas isinjected except by the formation.
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Harold Vance Department of Petroleum Engineering
Flowdrilli
ng a naturally fractured horizontal well
(courtesy of Signa Engineering Corporation)
Flow Drilling
Clear drill brine density less than or equal to 1.02 g/cm3
Oil, Gas, and Brine
9.5 ppg Brine
Pressure higher in HEEL ofwell causing lost returns
Pressure lower in TOEof well causes influx
Pore Pressure =3030 psi at 6234 ft
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Drilling Fluid Selection
Density is determined by:Maximum pressure to
formation pressure.Minimum pressure dictated
by wellbore stability.
Pressure limitations ofdiverter and BOP equipment.
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Surface Equipment
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Sc
hematic of surface equipment required for flowdrilling(courtesy of Signa Engineering Corporation)
STACK
MUD PITS
UNDERBALANCEDRILLING
MANIFOLD
GAS/FLUIDSEPARATION
SYSTEM
CHEMICALINJECTION
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Harold Vance Department of Petroleum Engineering
Surface Equipment
Atmospheric surface system for flowdrilling
(courtesy of Signa Engineering Corporation)
Grade
Gas boot (open on bottom)
4 in. Flare
6 in. Flare
12 in. Flare
4-6 in.
GasSeparator
GasSeparator Skimmer tanks
Water to rig
ChokeManifold ROP
AnnularPreventer
Pipe RamsBlind Rams
Pipe Rams
Oil tank
Oil to treatmentoff location
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Harold Vance Department of Petroleum Engineering
Typical flowdrilling BOP stack
(courtesy of Signa Engineering Corporation)
Surface Equipment
Choke Line
RBOP
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Surface Equipment
Rotating blowout preventer (RBOP).
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Surface Equipment
HydraulicFluid
Nitrile
Kelly Packer
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Surface Equipment
A typical flowdrilling choke manifold
(courtesy of Signa Engineering Corporation)
HydraulicChoke
ManualChoke
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Sizing Flare Line
Weymouthsequation can be
used to predict the pressuredrop for a gas, in steady-state, adiabatic, flow alongthe pipe:
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Sizing Flare Line
Harold Vance Department of Petroleum Engineering
Where:
Q gas flow rate (scf/D)d inside diameter of the pipe (the gas flare line in this
case) (inches)To standard temperature (520
oF)Po standard pressure (14.7 psia)
S gas gravity (air = 1)T pressure above the bit (psfa)L bottomhole pressure below the bit (psia)Za average compressibility factor (Weymouth used Za= 1)P1,P2 the inlet and outlet pressures (psia)
Q = 433.5 To d16/3
(P2
1-P2
2)Po STLZa
2.73
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Sizing Flare Line
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Weymouth's Equation 2.73incorporates a friction factor,
f = 0.032/d1/3
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Assuming a gas gravity of 0.6, andsubstituting for standard temperatureand pressure, Equation (2.73)becomes:
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Sizing Flare Line
Q = 19,754
d16/3(P21-P2
2)
TL
2.74
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Q2TL
2.06d16/3
2.75
Converting length, L, from miles tofeet, and flow rate, Q, from scf/D to
MMscf/D, the inlet pressure, P1, is:
Sizing Flare Line
P1= + P22
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The pressure differential exerted bythe U-tube head can be expressed as:
Where: specific gravity of the fluid in the
U-tube or separator.h height from the top of the gas
boot to the bottom of the U-tube(feet).
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Sizing Flare Line
P1P2= 0.433h
2.76
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Q2TL
2.06d16/3
2.77
Equations (2.75) and (2.76) can becombined to solve for the U-tube height,in terms of the gas flow rate,temperature, outlet (atmospheric)pressure, and flare line diameter:
Harold Vance Department of Petroleum Engineering
Sizing Flare Line
+ P22 - P2
h =
0.433
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Surface Pits
Primary oil separation pit.
Secondary oil separation pit.Skimmer system safety.
Drilling fluid pit.
Oil transfer tank.
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Operating Procedures
Mechanical objectives duringflow drilling are: To control the well.
Minimize differential stickingproblems.
Minimize drilling fluids losses.
Maximum tolerable surfacespressures should be establishedbefore drilling starts.
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Mudcap Drilling
Utilized with uncontrollable lossof circulation during flowdrilling
operations.Higher pressures than can be
safely handled with the rotating
head or RBOP.It is not strictly an underbalanced
drilling technique.
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Driller loads the annulus with arelatively high density high viscositymud and closes the choke withsurface pressure maintained.
Drilling is then continued blindby
pumping a clear non-damaging fluiddown the drillstring through the bitand into the thief zone.
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Mudcap Drilling
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Applications:
Sustained surface pressuresin excess of 2,000 psi.
Sour oil and gas production.
Small diameter wellbores.
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Mudcap Drilling
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Mudcap Drilling
Mudcap Interface(Formation Fluid / Drillwater)
Viscous Fluid Mudcap
Water replacement information fractures
An example of mudcap drilling
(courtesy of Signa Engineering Corporation)
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Harold Vance Department of Petroleum Engineering
MUDPITS
MUDPUMPS
RIG FLOOR
GASBUSTER To flare pit
HCR Valve(Closed)
CHOKE(closed)
DIVERTER
ChemicalInjection
Mudcap Drilling
Schematic of equipment required for mudcap drilling
(courtesy of Signa Engineering Corporation)
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Determining Pore Pressure
Harold Vance Department of Petroleum Engineering
Determining the Reservoir Pressure Along the Wellbore
Pore Pressure Bore Hole Pressure PP Datum
D
epth
(TVD)/1
,000,
ft.
Pressure, psi9,200 9,400 9,600 9,800
12.0
11.8
12.2
12.4
12.6
12.8
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Static Standpipe Pressures
PSPPstatic= 0.052 (EMWpore pressure- MWinjection fluid)TVD
Where:PSPPstatic static standpipe pressure, psi.
EMWpore pressure equivalent mud weight of formationpore pressure, ppg.
MWinjection fluid density of the injection fluid, ppg.
TVD true vertical depth of the top ofreservoir, ft.
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Dynamic Standpipe Pressures
PSPINJECTION= PSPPstatic+PDP+P Drill collars+PMWD+P Motor+P Bit+P frac
Where:PSPINJECTION standpipe pressure while circulating or injecting
down drillpipe..PSPPstatic static standpipe pressure, psi.
PDP frictional pressure drop of fluid flowing down drillpipe.P
Drill collars frictional pressure drop of fluid flowing down drill collars.
PMWD pressure drop across the measurement-while drilling tool.P Motor pressure loss to power motor.P Bit pressure drop across bit nozzles.P frac frictional pressure drop of fluid flowing through fractures.
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ExampleGiven:
The reservoir described above. A directional hole is tobe drilled with a 4-in. mud motor that requires aflow rate of 240 gpm resulting in a 400-psi on-bottompressure differential. MWD pressure drop is equal to150 psi. The MWD and Motor together have a total
length of 60 ft. The drillpipe to be used is 3-in.13.3 lb/ft. No Drill Collars are in the string. Nozzlesare (3) 17s (32nd of an inch). Assume the pressuredrop through the fractures is 100 psi and averageinjection water viscosity is 0.5 cp.
Find:
The circulating standpipe pressure at the top andbottom of the formation.
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Formation Top Formation Bottom
PSPPstatic 4,156 psi 4,129 psiPDP 710 psi 948 psiPDC 0 psi 0 psiPMWD 150 psi 150 psi
PMotor 400 psi 400 psiPBit 100 psi 100 psiPfrac 100 psi 100 psi
PSPINJECTION Formation Top:
4,156+713+0+150+400+100+100=5,616 psi
PSPINJECTION Formation Bottom:4,129+948+0+150+400+100+100=5,827psi
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Example
l
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If the circulating system is limited to only 5,000 psi inthe example above, the injection fluid density can be
increased to lower the required injection pressure. If theinjection fluid is changed to 10.0 ppg (average viscosityof 0.8 cp), then the standpipe pressures will be asfollows:
Example
Formation Top Formation Bottom
PSPPstatic = 3,120 psi 3,050 psiPDP = 915 psi 1,222 psiPDC = 0 psi 0 psiPMWD = 150 psi 150 psiPMotor = 400 psi 400 psiPBit = 120 psi 120 psi
Pfrac = 100 psi 100 psi
PSPINJECTION Formation Top:3,120+915+0+150+400+120+100= 4,805psi
PSPINJECTION Formation Bottom:
3,050+1,222+0+150+400+120+100=5,042psi Harold Vance Department of Petroleum Engineering
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Fluid Volume Requirements
The drillpipe injection rate during Mudcapoperations can be expressed simply as:
QDP = 0.0408 (IDHole2- ODDrillpipe
2)/AV
Where:QDP injection rate down the drillpipe, gpmIDHole hole or casing inside diameter, in.
ODDrillpipe drillpipe outside diameter, in.AV annular velocity across drillpipe-casing
annulus, ft/min.
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Fluid Volume Requirements
The cumulative daily drillpipe injection volumeconsumed may be expressed as:
QDP DailyCum = (18/24)QDP(60)(24/42)
This assumes 18 hrs of circulation/injection over a24-hour period.
Where:QDP DailyCum daily cumulative injectionvolume down the drillpipe, bbls
QDP defined by equation above
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Fluid Volume RequirementsGiven:
MCD is planned for a 6 1/8-in. hole using 3-in., 13.3 lb/ft drillpipe and 4-in. mud motor.Assume desired minimum AV = 100 ft/min
Find:
Minimum injection rate and minimum dailyconsumption of injection fluid.
QDP = 0.0408 (6.1252
3.52
)/100 = 103 gpm
QDP DailyCum = 25.7*103 = 2,649bbls/day
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Annular volumes will depend
upon whether the operatordesires continuous or periodicinjection of annular fluids or
whether a floating mudcap isto be used.
Fluid Volume Requirements
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Fluid Volume Requirements
The amount of fluid to inject into the annulusperiodically can be estimated by:
QAnn = (SF)VHMTPI(IDHole2
-DDrillpipe2
)/1,029Where:QAnn periodic annular injection volume, bbls.SF safety factor
VHM hydrocarbon migration rate, ft/min.T PI time period between injection volumes, min.IDHole hole or casing inside diameter, inc.ODDrillpipe drillpipe outside diameter, inc.
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Fluid Volume Requirements
An estimate of the cumulative volumeinjected into the annulus daily can bedetermined with:
QAnn Daily Cum = 24*60*QAnn/TPI
Where:QAnn Daily Cum annular daily cumulative injection
volume, bbls/day.QAnn periodic annular injection volume,bbls.
T PI time period between injectionvolumes, min.
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ExampleGiven:
MCD is planned for a sour gas well in a fractured
reservoir. Use a gas migration rate of 15 ft/min. A6 1/8-in. hole is planned to be drilled using 3-in., 13.3 lb/ft drillpipe. Use the periodic injectionmethod with time between injection periods equalto 30 minutes. Assume a safety factor of 2.
Find:
The minimum daily annular fluid or mudcapvolume requirement.
QAnn = 2*15*30*(6.125 2-3.5 2)/1,029 = 22 bbls.
QAnn Daily Cum = 24*60*22/30 = 1,060 bbls/day
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Snub Drilling
UBD operation utilizing asnubbing unit or coiled tubing
unit.Expense is justifiable if very
high formation pressures are
anticipated, and uncontrollableloss of circulation is expected.
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Harold Vance Department of Petroleum Engineering
OPERATORSSLIP CONSOLE
TRAVELINGSLIP
ASSEMBLY
OPERATORSBOP CONSOLE
STATIONARYSLIP
ASSEMBLY
SHEAVES
SWIVEL BASE ASSEMBLY
UPPERCABLEGUIDE
SNUBBINGCABLES
COUNTERBALANCEWEIGHTS
SNATCHBLOCK
PIPEGUIDE
STANDGUIDE
WORKBASKET
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Harold Vance Department of Petroleum Engineering
STAND PIPE
HYDRAULICEQUALIZINGVALVES
STATIONARY SLIPS
DUAL WINCH
CONTROL CONSOLEWORK BASKET
TRAVELING SLIPS
ROTARY TABLEKELLY HOSE
DUAL SHEAVE DROWN
POWER PACKFUEL TANK
TOOL BOX
HOSEBASKET
RISERSPOOLS
BOP
STRIPPER
TONGARM
SWIWEL
PIPEELEVATOR
POWER TONG
STARTING VALVE
PIPE RACKS PUMPMANIFOLD
QIN POLE
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BOP stack ( courtesy of Signa Engineering Corporation)
RIG FLOOR
Drilling Spool7-1/16, 10M x 7-1/16,5M
Cameron single7-1/6, 10M
Annular PreventerCameron 7-1/16, 10M
Cameron U double7-1/16, 10M
Frac Valve7-1/16, 10M
Install companion flange
w/2 WECO 1502 thread
Drilling Spool7-1/16, 15M x 10M
Cameron U double7-1/16, 15M
DSA7-1/16, 10M x 7-1/16, 15M
TUBING HEAD
11, 5M x 7-1/16, 10MOutlet with (2) 1-13/1610M Gate Valve
SOW CASING HEAD
11, 5M x 9-5/8,
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Harold Vance Department of Petroleum Engineering
Snub drilling choke system( courtesy of Signa Engineering Corporation)
6 GAS
6 GAS
4 GAS
GAS + LIQUID
DRILLING FLUIDRETURN
DRILLING FLUIDRETURN
GasBuster
GasBuster
LIQUIDLIQUID
ADJUSTABLEMANUAL CHOKE MANUALCHOKE HYD.LCHOKE
ALLGAS
FLAREPIT
SKIMMER
SANDSEPARATER
MUD PIT
WELLHEAD
PrevailingWind Direction
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Closed Systems
Refers to UBD operationswith a specific surface
system.A pressurized, four phase
separator and a fully closed
surface system, is used tohandle the returned fluids.
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Harold Vance Department of Petroleum Engineering
A typical closed surface system (modified after Lunan, 19942).
ProductionTank
Pressure VesselChoke Manifold
Stack
Drilling Fluid Tank Rig Pump Vaporizor
Mix
N2Pumpers
Ignitor
Flere Stack
Sample Catcher
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Harold Vance Department of Petroleum Engineering
Flow control arrangement (after Saponja, 19957).
Rotating Blow outPreventer/Diverter
CasingSpool
TubingSpool
Choke
Surface Casing300-400m, 508.0mm
Intermediate Casing1300-1450m, 339.7mm
Production Casing1890m, 244.5mm
Kill Line
Shear/Blind Rams
127mm (5) PipeRams
Kill Line
Annular Preventer
127mm (5) PipeRams
RBOP Height1700 mm
Choke Flare Pit
HCR
Choke LineConnected toRig Manifold
ChokeRig Manifold
Choke Line Connected toNorthland Separator Manifold
Annular Returns to ChokeManifold and Separator
To Shala ShakerRBOP
ESD
Northland Manifold
Sample Catchers
Wills Choke
Flare Stack
Separator200 psi Vessel
Water Returnedto Rig Tanks
Oil Storage/Transport
6 Gate Valve
4 Globe Valves
Rotating Blow outPreventer/Diverter
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Harold Vance Department of Petroleum Engineering
Integrated flow control and sample catcher manifold(after Lunan and Boote, 199412).
Valve#2
Sample Catcher #1
Full BoreValve #2
Full BoreValve #1
Valve#1
Valve#4
Valve #3
ChokeBypass
InputDataHeader
WellEffluents
FlowDirection
OutputDataHeader
FlowDirection
Sample Catcher #2
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Harold Vance Department of Petroleum Engineering
A typical, horizontal, four-phase separator, for underbalancedrilling (after Lunan and Boote, 199412).
GasGas
Adjustable Partition Plates
Velocity Reducer
Well
Effluents In
Continuous PressurizedSolids Transfer Pump
Gas Out
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Other Surface Equipment
Cuttings filter.
Heater.
Degasser.
Flare stack/pit.
Production tank.
Water tank.Solids tank.
Instrumentation.