lesson 10 flow mudcap snub closed systems1

8/12/2019 Lesson 10 Flow Mudcap Snub Closed Systems1

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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)

Harold Vance Department of Petroleum Engineering


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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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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


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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Surface Equipment

Atmospheric surface system for flowdrilling


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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Typical flowdrilling BOP stack


Surface Equipment

Choke Line

RBOP


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Surface Equipment

Rotating blowout preventer (RBOP).


9/50RBOP sealing elementsHarold Vance Department of Petroleum Engineering

Surface Equipment

HydraulicFluid

Nitrile

Kelly Packer


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Surface Equipment

A typical flowdrilling choke manifold


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


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


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:


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).


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:


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.


Mudcap Drilling


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Applications:

Sustained surface pressuresin excess of 2,000 psi.

Sour oil and gas production.

Small diameter wellbores.


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



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MUDPITS

MUDPUMPS

RIG FLOOR

GASBUSTER To flare pit

HCR Valve(Closed)

CHOKE(closed)

DIVERTER

ChemicalInjection

Mudcap Drilling

Schematic of equipment required for mudcap drilling



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Determining Pore Pressure


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


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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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.




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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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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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OPERATORSSLIP CONSOLE

TRAVELINGSLIP

ASSEMBLY

OPERATORSBOP CONSOLE

STATIONARYSLIP

ASSEMBLY

SHEAVES

SWIVEL BASE ASSEMBLY

UPPERCABLEGUIDE

SNUBBINGCABLES

COUNTERBALANCEWEIGHTS

SNATCHBLOCK

PIPEGUIDE

STANDGUIDE

WORKBASKET


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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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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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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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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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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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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.

lesson 10 flow mudcap snub closed systems1

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