Flow Drilling Mudcap Drilling

1
PETE 689 Underbalanced Drilling (UBD)

• Lesson 10
• Flow Drilling Mudcap Drilling
• Snub Drilling
• Closed Systems
• Read UDM Chapter 2.8-2.11
• Pages 2.180-2.219

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2
Flow Drilling

• Flow drilling refers to drilling operations in
  which the well is allowed to flow to surface
  while drilling.
• All UBD operations are really flow drilling
  operations, but the term is usually applied to
  drilling with a single phase mud, and no gas is
  injected except by the formation.

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3
Flow Drilling
Clear drill brine density less than or equal to
1.02 g/cm3
Oil, Gas, and Brine
9.5 ppg Brine
Pressure lower in TOE of well causes influx
Pressure higher in HEEL of well causing lost
returns
Pore Pressure 3030 psi at 6234 ft
Flowdrilling a naturally fractured horizontal
well (courtesy of Signa Engineering Corporation)
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Drilling Fluid Selection

• Density is determined by
• Maximum pressure to formation pressure.
• Minimum pressure dictated by wellbore stability.
• Pressure limitations of diverter and BOP
  equipment.

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Surface Equipment
MUD PITS
STACK
CHEMICAL INJECTION
GAS/FLUID SEPARATION SYSTEM
UNDERBALANCE DRILLING MANIFOLD
Schematic of surface equipment required for
flowdrilling (courtesy of Signa Engineering
Corporation)
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Surface Equipment
12 in. Flare
6 in. Flare
4-6 in.
4 in. Flare
Gas boot (open on bottom)
Water to rig
Grade
Gas Separator
Gas Separator
Skimmer tanks
Choke Manifold
ROP
Annular Preventer
Oil tank
Pipe Rams
Blind Rams
Oil to treatment off location
Pipe Rams
Atmospheric surface system for flowdrilling (court
esy of Signa Engineering Corporation)
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Surface Equipment
RBOP
Choke Line
Typical flowdrilling BOP stack (courtesy of
Signa Engineering Corporation)
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Surface Equipment
Rotating blowout preventer (RBOP).
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Surface Equipment
Kelly Packer
Hydraulic Fluid
Nitrile
RBOP sealing elements
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Surface Equipment
Manual Choke
Hydraulic Choke
A typical flowdrilling choke manifold (courtesy
of Signa Engineering Corporation)
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Sizing Flare Line
Weymouths equation can be used to predict the
pressure drop for a gas, in steady-state,
adiabatic, flow along the pipe
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Sizing Flare Line
To d16/3(P21-P22) Po
STLZa
2.73
Q 433.5
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 fluids density
below the bit (lbm/ft3) 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)
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Sizing Flare Line
Weymouth's Equation 2.73 incorporates a friction
factor, f 0.032/d1/3
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Sizing Flare Line
Assuming a gas gravity of 0.6, and substituting
for standard temperature and pressure, Equation
(2.73) becomes
d16/3(P21-P22)
TL
2.74
Q 19,754
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Harold Vance Department of Petroleum Engineering
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Sizing Flare Line
Converting length, L, from miles to feet, and
flow rate, Q, from scf/D to MMscf/D, the inlet
pressure, P1, is
Q2TL 2.06d16/3
2.75
P1 P22
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Sizing Flare Line
The pressure differential exerted by the U-tube
head can be expressed as
P1 P2 0.433?h
2.76
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
Equations (2.75) and (2.76) can be combined to
solve for the U-tube height, in terms of the gas
flow rate, temperature, outlet (atmospheric)
pressure, and flare line diameter
Q2TL 2.06d16/3


2.77
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 during flow drilling are
• To control the well.
• Minimize differential sticking problems.
• Minimize drilling fluids losses.
• Maximum tolerable surfaces pressures should be
  established before drilling starts.

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Mudcap Drilling

• Utilized with uncontrollable loss of 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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Mudcap Drilling

• Driller loads the annulus with a relatively high
  density high viscosity mud and closes the choke
  with surface pressure maintained.
• Drilling is then continued blind by pumping a
  clear non-damaging fluid down the drillstring
  through the bit and into the thief zone.

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Mudcap Drilling

• Applications
• Sustained surface pressures in excess of 2,000
  psi.
• Sour oil and gas production.
• Small diameter wellbores.

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Mudcap Drilling
Viscous Fluid Mudcap
Mudcap Interface (Formation
Fluid / Drillwater)
Water replacement in formation fractures
An example of mudcap drilling
(courtesy of Signa
Engineering Corporation)
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Mudcap Drilling
GAS BUSTER
To flare pit
MUD PITS
RIG FLOOR
Chemical Injection
HCR Valve (Closed)
MUD PUMPS
CHOKE (closed)
DIVERTER
Schematic of equipment required for mudcap
drilling (courtesy of Signa Engineering
Corporation)
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Determining Pore Pressure
Pressure, psi
9,200 9,400
9,600 9,800
11.8
12.0
12.2
Depth (TVD)/ 1,000, ft.
12.4
12.6
12.8
Determining the Reservoir Pressure Along the
Wellbore
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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 formation pore
pressure, ppg. MWinjection fluid density of
the injection fluid, ppg. TVD true vertical
depth of the top of reservoir, ft.
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Example
Given Reservoir described in Figure 3-1-2.
Injection fluid is fresh water with no additives.
A lateral is planned to intersect the formation
top at 12,750 MD (20,000 TVD) and encounter the
formation bottom at TD of 17,000 MD (12,500
TVD). Fractures exist at both the top and the
bottom of the formation. Find Maximum static
standpipe pressure when the bit is at the top and
at the bottom of the formation.
Formation To
Formation Bottom EMWpore pressure 15
ppg 14.7 ppg MWinjection fluid 8.34
ppg 8.34 ppg TVD 12,000 ft 12,500 ft
PSPPstatic 0.052(15-8.34)12,000
0.052(15-8.34)12,000 4,156
psi 4,129 psi
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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.
Harold Vance Department of Petroleum Engineering
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Example
Given The reservoir described above. A
directional hole is to be drilled with a 4¾-in.
mud motor that requires a flow rate of 240 gpm
resulting in a 400-psi on-bottom pressure
differential. MWD pressure drop is equal to 150
psi. The MWD and Motor together have a total
length of 60 ft. The drillpipe to be used is
3½-in. 13.3 lb/ft. No Drill Collars are in the
string. Nozzles are (3) 17s (32nd of an inch).
Assume the pressure drop through the fractures is
100 psi and average injection water viscosity is
0.5 cp. Find The circulating standpipe
pressure at the top and bottom of the
formation.
Harold Vance Department of Petroleum Engineering
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Example
Formation Top Formation Bottom PSPPstatic
4,156 psi
4,129 psi ?PDP 710
psi 948 psi ?PDC
0 psi
0 psi ?PMWD
150 psi 150
psi ?PMotor 400 psi
400 psi ?PBit 100
psi 100 psi ?Pfrac
100 psi 100 psi
PSPINJECTION Formation Top
4,15671301504001001005,616
psi PSPINJECTION Formation Bottom
4,12994801504001001005,827psi
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Example
If the circulating system is limited to only
5,000 psi in the example above, the injection
fluid density can be increased to lower the
required injection pressure. If the injection
fluid is changed to 10.0 ppg (average viscosity
of 0.8 cp), then the standpipe pressures will be
as follows
Formation Top Formation
Bottom PSPPstatic 3,120 psi 3,050
psi ?PDP 915 psi 1,222
psi ?PDC 0 psi
0 psi ?PMWD 150 psi 150
psi ?PMotor 400 psi 400
psi ?PBit 120 psi 120
psi ?Pfrac 100 psi 100 psi
PSPINJECTION Formation Top
3,1209150150400120100 4,805psi PSPINJECTI
ON Formation Bottom
3,0501,22201504001201005,042psi
Harold Vance Department of Petroleum Engineering
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Fluid Volume Requirements
The drillpipe injection rate during Mudcap
operations can be expressed simply as
QDP 0.0408 (IDHole2 - ODDrillpipe2)/AV
Where QDP injection rate down the
drillpipe, gpm IDHole hole or
casing inside diameter, in. ODDrillpipe
drillpipe outside diameter, in. AV
annular velocity across drillpipe-casing
annulus, ft/min.
Harold Vance Department of Petroleum Engineering
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Fluid Volume Requirements
The cumulative daily drillpipe injection volume
consumed may be expressed as
QDP DailyCum (18/24)QDP(60)(24/42)
This assumes 18 hrs of circulation/injection over
a 24-hour period.
Where QDP DailyCum daily cumulative
injection volume down the drillpipe,
bbls QDP defined by equation above
Harold Vance Department of Petroleum Engineering
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Fluid Volume Requirements
Given MCD is planned for a 6 1/8-in. hole using
3½-in., 13.3 lb/ft drillpipe and 4¾-in. mud
motor. Assume desired minimum AV 100
ft/min Find Minimum injection rate and
minimum daily consumption of injection fluid.
QDP 0.0408 (6.125 2 3.5 2)/100 103 gpm
QDP DailyCum 25.7103 2,649 bbls/day
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Fluid Volume Requirements

• Annular volumes will depend upon whether the
  operator desires continuous or periodic injection
  of annular fluids or whether a floating mudcap is
  to be used.

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Fluid Volume Requirements
The amount of fluid to inject into the annulus
periodically can be estimated by
QAnn (SF)VHMTPI(IDHole2 -DDrillpipe2)/1,029
Where 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.
Harold Vance Department of Petroleum Engineering
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Fluid Volume Requirements
An estimate of the cumulative volume injected
into the annulus daily can be determined with
QAnn Daily Cum 2460QAnn/TPI
Where QAnn Daily Cum annular daily
cumulative injection volume,
bbls/day. QAnn periodic annular
injection volume, bbls. T PI
time period between injection
volumes, min.
Harold Vance Department of Petroleum Engineering
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Example
Given MCD is planned for a sour gas well in a
fractured reservoir. Use a gas migration rate of
15 ft/min. A 6 1/8-in. hole is planned to be
drilled using 3½-in., 13.3 lb/ft drillpipe. Use
the periodic injection method with time between
injection periods equal to 30 minutes. Assume a
safety factor of 2. Find The minimum daily
annular fluid or mudcap volume requirement.
QAnn 21530(6.125 2 -3.5 2)/1,029 22 bbls.
QAnn Daily Cum 246022/30 1,060 bbls/day
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Snub Drilling

• UBD operation utilizing a snubbing unit or coiled
  tubing unit.
• Expense is justifiable if very high formation
  pressures are anticipated, and uncontrollable
  loss of circulation is expected.

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UPPER CABLE GUIDE
SNUBBING CABLES
COUNTER BALANCE WEIGHTS
SNATCH BLOCK
PIPE GUIDE
TRAVELING SLIP ASSEMBLY
STANDGUIDE
OPERATORS SLIP CONSOLE
OPERATORS BOP CONSOLE
WORK BASKET
STATIONARY SLIP ASSEMBLY
SHEAVES
SWIVEL BASE ASSEMBLY
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DUAL SHEAVE DROWN
SWIWEL
QIN POLE
STARTING VALVE
TRAVELING SLIPS
TONG ARM
ROTARY TABLE
KELLY HOSE
POWER TONG
CONTROL CONSOLE
PIPE ELEVATOR
WORK BASKET
DUAL WINCH
STATIONARY SLIPS
STAND PIPE
HYDRAULIC EQUALIZING VALVES
STRIPPER
POWER PACK
BOP
FUEL TANK
TOOL BOX
RISER SPOOLS
PIPE RACKS
PUMP MANIFOLD
HOSE BASKET
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7 26 _at_ 8128
Top of productive interval _at_ 8157
KOP _at_ 8302
Pilot hole dressed off to 8285
60 deg
6-1/8 Hole to 8550
4-3/4 Hole
FORMATION DIP 6-80 N 820E
8558
(Secondary Target)
SHALE
8578
SHALE
Target Center
8594
(Primary Target)
8618
Pilot Hole
Top of SHALE 8821
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Drilling Spool
7-1/16, 10M x 7-1/16,5M
RIG FLOOR
Cameron single 7-1/6, 10M
Annular Preventer Cameron 7-1/16, 10M
Cameron U double 7-1/16, 10M
Install companion flange w/2 WECO 1502 thread
Drilling Spool 7-1/16, 15M x 10M
Cameron U double 7-1/16, 15M
DSA
7-1/16, 10M x 7-1/16, 15M
Frac Valve
7-1/16, 10M
TUBING HEAD 11, 5M x
7-1/16, 10M
Outlet with (2) 1-13/16 10M Gate Valve
SOW CASING HEAD 11, 5M x
9-5/8,
BOP stack ( courtesy of Signa Engineering
Corporation)
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FLARE PIT
6 GAS
LIQUID
Gas Buster
LIQUID
6 GAS
Gas Buster
SKIMMER
4 GAS
DRILLING FLUID RETURN
ALL GAS
MUD PIT
ADJUSTABLE MANUAL CHOKE
HYD.L CHOKE
MANUAL CHOKE
DRILLING FLUID RETURN
GAS LIQUID
SAND SEPARATER
Prevailing Wind Direction
WELLHEAD
Snub drilling choke system
( courtesy of Signa
Engineering Corporation)
Harold Vance Department of Petroleum Engineering
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Closed Systems

• Refers to UBD operations with a specific surface
  system.
• A pressurized, four phase separator and a fully
  closed surface system, is used to handle the
  returned fluids.

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Ignitor
Flere Stack
Sample Catcher
Stack
Pressure Vessel
Choke Manifold
Production Tank
N2 Pumpers
Mix
Drilling Fluid Tank
Vaporizor
Rig Pump
A typical closed surface system (modified after
Lunan, 19942).
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Rotating Blow out Preventer/Diverter
Rotating Blow out Preventer/Diverter
To Shala Shaker
RBOP
ESD
Northland Manifold
RBOP Height 1700 mm
Sample Catchers
6 Gate Valve
Annular Returns to Choke Manifold and Separator
4 Globe Valves
Annular Preventer
Wills Choke
127mm (5) Pipe Rams
Flare Stack
Choke Line Connected to Northland Separator
Manifold
Kill Line
Separator 200 psi Vessel
Shear/Blind Rams
Rig Manifold
Choke
Choke
Choke Line Connected to Rig Manifold
127mm (5) Pipe Rams
Water Returned to Rig Tanks
Oil Storage/ Transport
Kill Line
HCR
Tubing Spool
Choke
Flare Pit
Casing Spool
Surface Casing 300-400m, 508.0mm
Intermediate Casing 1300-1450m, 339.7mm
Production Casing 1890m, 244.5mm
Flow control arrangement (after Saponja, 19957).
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Flow Direction
Output Data Header
Valve 2
Sample Catcher 1
Sample Catcher 2
Valve 3
Full Bore Valve 2
Full Bore Valve 1
Valve 1
Choke Bypass
Well Effluents
Input Data Header
Valve 4
Flow Direction
Integrated flow control and sample catcher
manifold (after Lunan and Boote,
199412).
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Well Effluents In
Adjustable Partition Plates
Gas Out
Velocity Reducer
Gas
Gas
Continuous Pressurized Solids Transfer Pump
A typical, horizontal, four-phase separator, for
underbalance drilling (after Lunan and Boote,
199412).
Harold Vance Department of Petroleum Engineering
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Other Surface Equipment

• Cuttings filter.
• Heater.
• Degasser.
• Flare stack/pit.
• Production tank.
• Water tank.
• Solids tank.
• Instrumentation.

Harold Vance Department of Petroleum Engineering