General Considerations,

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Lesson 14
PETE 689 Underbalanced Drilling (UBD)

• General Considerations,
• Completion Tools

2
The Reason for UB Drilling Determines the
Completion Type

• Faster Rate of Penetration.
• Lost Circulation.
• Differential Pressure Sticking.
• Formation Evaluation.
• Prevention of Formation Damage.

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UB Completion Types

• Open Hole
• Liners
• Cased Hole

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Advantages of UB Open Hole Completion

• Simple
• Low Cost
• Low Maintenance

5
Disadvantages of UB Open Hole Completion

• Difficult Well Control
• Borehole Stability
• Formation Specific
• Entire Formation Exposed
• No Zonal Isolation

6
Open Hole CompletionGeneral Considerations

• Intermediate Casing Point
• Stripping or snubbing head
• Tripping In and Out
• Drill String
• Tubing
• Well Head Installation

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Isolating BHP From Surface in Open-Hole
Completions

• While tripping.
• Running completion tools.
• Installing tubing head and tree.

8
Isolating BHP From Surface

• Isolation Valve
• Temporary Plug
• Floating Mud Cap
• Strip and Snub
• Kill the well with mud

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Isolation Valve for Completion / Drilling

• Halliburton
• Petrolane/Weatherford
• Techcorp (Canada)

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Well Control Valve HALLIBURTON

• Valve goes at about 3,000
• Deeper is not necessary.
• Runs on a liner that ties into intermediate
  casing.

Well Control Valve
Back off threads
Hanger
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Well Control Valve HALLIBURTON

• Valve closes against upward pressure
• Trip without stripping
• Balance pressure to open valve.

Well Control Valve
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Well Control Valve HALLIBURTON

• The float valve is opened by the bit.

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Well Control Valve HALLIBURTON

• The float valve is closed when the bit pulls
  the sleeve the bit.
• The sleeve rides the drill pipe up and out of the
  hole.

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Completion Isolation Valve(Petroline)

• Safe underbalanced completion running.
• Bi-directional suspension barrier.
• Interventionless completion installation.
• Tool deployment barrier.
• Remote opening from surface.

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Liner Top Operational Sequence
Run outer and inner string to depth and set liner
hanger
Release liner hanger running tools and pull back
to inflate ECP
Pull back into larger ID section to activate
shifting tool no-go mechanism
Run in to land and lock, shifting tool
in TB-CIV. Pull ball closed
Shear shifting tool and pull back. Pressure test
and circulate to completion fluid
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Tool Deployment Operational Sequence
Run guns and spot underbalance cushion if required
Fire guns
Pull back to close CIV pressure tests
Retrieve guns re-deploy as required
shifting CIV open
Pressure cycle CIV open
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Temporary Completion Plug

• Activate/Release with Tubing.
• Restriction at TD.
• Through-Tubing Bridge Plug.

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Completion Types

• Open Hole
• Various liners
• Cased Hole

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Slotted Liner in UB Completion - Considerations

• Stripping and snubbing
• Downhole lubricator
• Temporary plug
• Standard overshot on liner
• Drill-in liner
• Expandable liner

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Catching and Movinga Downhole Lubricator
21
Expandable Liners
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Petroline Alternative Borehole Liner (ABL)
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ABL Advantages

• Reduced well costs, low cost contingency.
• Larger bore production casing allows easier
  access/larger completion accessories.
• Can allow larger production conduits.
• Can eliminate sidetracks, therefore well on line
  earlier.
• In prolific reservoirs, large production
  increases possible due to larger payzone diameter.

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ABL Key Uses

• Isolation of problem zones
• Swelling Clay
• Sloughing shales
• Fluid loss zones
• Under/over pressured zones
• Differential sticking
• Additional contingency casing strings without
  loss of hole size.
• Incomplete casing run - can be set below shoe to
  isolate exposed formations.
• An integral element of Slim hole well design.

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ABL Key Uses

• Reduces well 'telescoping'
• Not limited by length/diameter.
• Relatively simple, robust tools.
• Permits fundamental changes in well design.

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Running Tool

• Accommodates the expansion cone and two drift
  cones.
• Bottom part contains shearing device to which the
  expandable top connector is made-up.

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Expandable Top Connector

• Interface between the running tool and the ABL
  string and contains the locations for the shear
  pins.

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ABL Joints

• Supplied in 40 ft lengths.
• Also available in pup joints of different
  lengths.
• All joints internally coated with a polyurethane
  sealant which allows circulation.

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Expandable Bottom Connector

• Interface between Anchor Shoe and ABL string.
• The Anchor Shoe is made of aluminum and is
  drillable in approx. 30 minutes.

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ABL Deployment
31
Deployment Procedure
Set Conventional Casing
Drill New Zone Overgauge (Under-Ream if Necessary)
Run in Hole EST ABL
Cement ABL
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Deployment Procedure
Expanded ABL While Cement Soft
Expanded ABL Let Cement Harden
Drill Out Hard Cement
Continue New Section Without Loss of Hole Size
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ABL as a Completion Liner
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Expandable Completion Liner

• Isolates annulus from pay zone.
• Allows slimming down of well by one casing size.
• Improves mud cake removal.
• Improved PLT interpretation.
• Maximizes inflow area.
• Stabilizes the formation.

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Conventional vs. ECL
36
Expandable Sand Screen
37
Conventional vs. ESS
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Completion Types

• Open Hole
• Various liners
• Cased Hole

39
Cased Hole-UB Completion

• Liner
• Use same technique
• Full String
• Strip/Snub
• Surge/Swab Potential

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Two-Stage Techniquein UB Completion

• Conventional or UBD Intermediate
• Drill out With CTU

41
Two-Stage Drilling Technique(Walker Hopmann,
1995)
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Multi-Lateral Root SystemTM
BAKER
HUGHES
Glass Disk
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Inflate ECP and cement liner into main bore
casing. Clean out liner. Perform any remedial
treatments if necessary.
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Coiled-Tubing UnitUB Completion

• Open Hole
• Slotted Liner
• Conventional Liner or Full String

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Casing/Liner Running Procedure

• Review Tripping and Connection procedures.
• Select Connection with smallest external upset.
• Use Range 3 to minimize connections
• Minimize External Accessories.
• Okay if well is Dead

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Pipe Running With Annular Pressure

• No Rigid Centralizers.
• No Scratchers.
• Coat ECP with grease.
• Minimize external upsets on liner
  hangers/packers.
• Use recessed slips
• Can remove inner element of RBOP while running
  liner.

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Perforated/Slotted Liners

• Significant Well Control Danger
• Must Kill Well First.
• Only Slot/Perf. bottom third of each joint.
• Slot only every second, third fourth , etc.
  joint.
• Pre-Plug slots with resin or wax.
• Pre-plug perfs. with plastic or aluminum.

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Perforated/Slotted Liners

• Keep one stand of casing with a pump-in swedge in
  the derrick.
• Option DP x Casing
• Be Prepared to drop the liner/casing and close
  blind rams.

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End
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Cementing

• (Chapter 8.4)

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Cementing UBis it Possible?

• UB Cementing
• ?
• Incompetent Cement
• OB Cementing
• ?
• Formation Damage

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Annular Flow Through Cement
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Formation Damage Mechanism in Cementing

• Slurry Damage
• Filtrate Damage

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Formation Damage From Cement
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Before cementing, remember why the well was
drilled underbalanced.
Minimize Damage
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Loading the Hole

• Casing Run Dry
• Straight
• Deviation requires lubrication.
• Stable Formation

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Advantages of Loadingthe Hole

• Clean the Hole

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Pack-Off Due to Sloughing
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Advantages of Loading the Hole

• Clean the Hole
• Prevent Pack-off
• Ensure Float Equipment is Open
• Remember gas compresses

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Temperature Effects

• Cool Steel Contracts
• Liners
• Minimum Two Circulations
• Set Down Weight

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Preventing Formation Damage in Cementing

• Low API FL
• Know the Slurry Rheology
• Know Frac and Pore Pressures
• Model Hydraulics
• Non-damaging Pre-flush

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Snubbing and Stripping
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SNUBBING - Pipe Light Where an external force is
needed to push pipe into the hole.
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STRIPPING - Pipe Heavy Condition. Where weight
of pipe exceeds well bore pressure.
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In any well control operation, the first and
foremost priority must always be the safety of
everyone involved.
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STRIPPING OPERATIONS

• Normal Stack Configurations can be used.
• Recommended not to exceed 50 of the rated
  working pressure.
• Pay attention to Volumetrics
• Stripping - maintain constant BHP
• Bleed Mud volume equal to Steel volume going in.

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Maintaining Seal Element Life

• Pass tool joints slowly.
• Lubricate Element.
• Reduce closing pressure to minimum.

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SNUBBING
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Rig up for Phase II
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Calculations

• The Depth of the Neutral Point.
• The Critical Buckling Load of the Work String for
  Support conditions of the Snubbing Unit.
• The jack system settings.
• Maximum Jack Speed.

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Forces on Snubbing String

• The Pressure Area Force Acting Upward.
• Gravity working downward.
• Frictional Forces.
• The Snubbing Unit Forces.
• Force of any Obstructions in well.

S Downward Forces S Upward Forces
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Snub Force String Weight
(Pressure x Area) Friction
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Upward force resulting from the wellhead pressure
against the pipe
Fp-a (? OD2 WHP) / 4
Where Fp-a pressure area force,
lbs OD diameter in which seal is made,
inches. WHP wellhead pressure, psi.
Remember tool joints!
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Max Snub Force Pressure Area Force Friction
Fmax snub Fp-a Ffriction
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Balance Point
Transition from pipe light to pipe heavy.
Bouyed String Weigh Pressure Area Force
WT Fp-a
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Bouyed Pipe Weight
WT Lw - (OD2 MWwell)/24.5
Where WT effective (bouyed) string weight,
lbs w pipe weight per foot in air,
lbs/foot L pipe length in the well,
feet MWwell fluid density in the well, ppg
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Balance Point
LB-P (?OD2WHP)/4 / w (OD2MWwell )/
24.5
Pressure Area Force Bouyed Weight
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Calculate increased weight due to filling pipe
?WT (LID2 MWstring)/24.5
Where ?WT change in string weight,
lbs ID pipe inside diameter, inches MWstring fl
uid density inside the work string, ppg
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Watch out for density variations inside and
outside the pipe
WT L w (ID2 MWstring)/24.5
. ..(OD2MWwell )/ 24.5)
Where WT total weight of the string considering
bouyancy and fill inside the pipe, lbs (all
other variables are the same as above)
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Next Step

• Snubbing force known.
• NOW determine whether or not the string to be
  used will buckle or not.

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Cross-Section of the Snubbing String
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Column Stability and Local Buckling
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Buckling Determination
1. Column Slenderness Ratio
Cc ?v (2E) / dy
2. Radius of Gyration
r v I / Asc
3. Effective Slenderness Ratio
SR (KL) / r or SR QRT(R/t)4.8
(R/225)t
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End Conditions Determine K Values
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Buckling Load(SRltCc)
BL dy As 1 - (SR2 / 2Cc2)
Where BL maximum buckling load (without safety
factor), lbs dy yield stress of the pipe,
psi As cross-sectional area of the pipe, inc.2
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In This Situation, The Buckling Load Can be
Increased By

• Increasing the work string size (OD).
• Increasing work string wall thickness.
• Increasing work string yield stress.

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If Slenderness Ration (SR) gt Column Slenderness
Ratio, Cc
BL As 286,000,000 / SR2
Where BL maximum buckling load (without safety
factor), lbs
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In This Situation, The Buckling Load Can be
Increased By

• Reducing the unsupported length.
• Increasing the work string size.
• Increasing the work string wall thickness.

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