Multilateral Well Completions and Interventions
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Multilateral Well Completions and Interventions
Why and How
8/25/2015 1 George E. King Engineering
GEKEngineering.com
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Application Objective
1. Multiple targets Increase reserves by combining targets that
separate reservoirs are separately uneconomic
isolated fault blocks
good quality sand bodies
2. Limited Size Targets Achieve high productivity in a confined
oil lenses space which would limit horizontal
bocks limited by conductive faults well length
3. Drainage Patterns Improve areal sweep
more linear flow
flexibility to control inflow location
modify over time by sidetracking
4. Completion by layer Improve vertical sweep
different prod. via layers
5. Improve Existing Wells Increase productivity and reserves
multilateral sidetracking
6. Handle Reservoir Geology Increase productivity
penetrate natural fractures
penetrate shale barriers
7. Limit water/gas production Reduce gas and water handling costs
reduce drawdown, less coning and loss of hydrocarbon production caused
distancing from faults by water or gas
8. Injection Increase injectivity.
new wells Improve areal and vertical sweep.
sidetracks of existing wells Reference: SPE 35711, Salas, et. al.
Some Potential Applications For Multi-lateral Wells
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Best Candidates
• Compartments
– vertical boundaries
– lenses
– fault blocks
• Launching points for fracs
• Launching points for more laterals??
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Multi-Laterals at Primrose
Stacked laterals with uncemented slotted liner in upper layer
~ 2000 ft
50 ft
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Multilaterals in Sharjah
Open hole laterals in the same layer
~ 4000 ft
~ 3000 ft
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Swell Packers
Across Shales
Quad-Lateral
(TAML-Level 4)
Producer/Injector
9200’ TVD
Thru-Tubing Retrievable Electric
Submersible
Pump (ESP)
Power Transfer Collar
ESP Feed through
Hydraulic Set Packer
Flow Meter
ESP Feed through
Hydraulic Set Packer
Flow Meter
Flow Meter
Flow Meter
ESP Feed through
Hydraulic Set Packer
ESP Feed through
Hydraulic Set Packer
SC-SSSV
ESP Feed through
Hydraulic Set Packer
5 ½” Tubing
to Surface
5 ½” Tubing
9 5/8” x TBD
IsoRite (LRS)
5 ½” Tubing
5 ½” Tubing
ESP Wire
9 5/8” x TBD
IsoRite (LRS)
9 5/8” x TBD
IsoRite (LRS)
ESP Wire
5 ½” Tubing
Mechanical Advantages • Thru-tubing retrievable pump and motor
• Access to all laterals
• Motherbore flow control
• Downhole/real time injection splits
• Potential lateral flow control*
• Access to log laterals and remedial work
Technology Developments • Power Transfer Method to ESP
(Inductance – Coil, Sealed “Wet Connect”)
• 7-Line Feed through Packer
(9 5/8” x 5 1/2” x 4.892”)
• Orienting and Locking Method for IsoRite LRS
(Lateral Re-Entry System)
Reservoir Benefits • Hot water for flooding cold, viscous
reservoir (200+ degrees F)
• Local source of water
• Potential improved horizontal sweep
TPI Isolation
Sleeve
TEW
Neckless
Swell Packers
Across Shales
Cemented Junction
Freeze Protect
(Crude or Methanol Water)
Cemented Junction
Cemented Junction
Shale
Shale
Injection Zone Injection Zone
High Perm
Shut Off Injection
(Straddle)
Injection Zone
Injection Zone
Injection Zone
Shale
Shale
Injection Zone
Injection Zone
Injection Zone
Shale
Shale
Top of Sad
Water Source
Swell
Packer
*Potential Lateral Flow Control
Straddle to Seal Off
or Reduce Injection
No Water Injection (Straddle)
Shale
Shale
Injection
Zone
Injection
Zone
Prepared By:
Jerry Brady…………. BPX Alaska
Joe Hess……………. Halliburton
Donn Schmohr…….. BPX Alaska
Mik Triolo…………… BPX Alaska
Scott Mattison……… BPX Alaska
Laura Larson………. BPX Alaska
9-5/8” Casing
12-1/4” Hole
10-3/4” Flush Joint
Casing
12-1/4” Hole
10-3/4” X 9-5/8”Casing Alignment
Sub 7” X 5-1/2” B X 5-1/2”P Keyed
Tubing Alignment Sub
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Amoco Norway Downhole Splitter
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Lateral Technology Levels • Level 1 - Open/Unsupported Junction
• Level 2 - Mother Bore Cased & Cemented, Lateral Open
• Level 3 - Mother Bore Cased & Cemented, Lateral Cased but not Cemented
• Level 4 - Mother Bore & Lateral Cased & Cemented
• Level 5 - Pressure Integrity at Junction (not cement)
• Level 6 - Pressure Integrity at Junction achieved with casing
• Level 6S - Downhole Splitter
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L e v e l 1 , 2 L e v e l 1 , 2 L e v e l 1 , 2 L e v e l 3 L e v e l 3 L e v e l 3
M u lti-la te ra l o p e n h o le o p e n h o le o p e n h o le l in e r l in e r l in e r
O p tio n s o p p o se d sta c k e d fo rk e d o p p o se d sta c k e d fo rk e d
H y d ra u l ic se a l a t ju n c tio n ? n o n e n o n e n o n e n o n e n o n e n o n e
Iso la tio n a lo n g w e l lb o re ? l im i te d l im i te d d i ffic u l t n o n o n o
P e rfo ra tin g p o ssib le ? d i ffic u l t v . d i ffic u l t y e s l im i te d v . d i ffic u l t l im i te d
L in e r/sc re e n in se rtio n p o ssib le ? y e s v . d i ffic u l t y e s y e s y e s y e s
L a rg e d ia m e te r la te ra l re c o m p .? y e s y e s y e s n o n o n o
P o ssib le u se in o ld w e l l? y e s d i ffic u l t y e s y e s y e s y e s
U se fu l in h ig h p re ssu re w e l l? n o n o n o n o n o n o
P o te n tia l in u n sta b le fo rm .? l im i te d n o l im i te d l im i te d l im i te d l im i te d
L a te r w a te r c o n tro l p o ssib le ? d i ffic u l t v . d i ffic u l t l im i te d n o n o n o
G e n e ra l stim u la tio n p o ssib le ? y e s y e s y e s y e s y e s y e s
M u l tip le stim u la tio n p o ssib le ? d i ffic u l t n o l im i te d n o n o n o
P ro d u c tio n c o n tro l p o te n tia l? d i ffic u l t n o l im i te d n o n o n o
En try w i th w ire l in e ? d i ffic u l t n o l im i te d l im i te d n o y e s
En try w i th C T ? y e s d i ffic u l t y e s y e s d i ffic u l t y e s
U p /d o w n d ip p o te n tia l? y e s l im i te d y e s y e s l im i te d y e s
R isk , n o t a c h ie v in g c o m p le tio n ? lo w m o d e ra te lo w m o d e ra te h ig h m o d e ra te
R isk , o f lo o sin g e n ti re w e l l? m o d m o d e ra te lo w lo w m o d e ra te lo w
C o st o f c o m p le tio n ? lo w m o d e ra te lo w m o d e ra te h ig h m o d e ra te
N u m b e rs D o n e m a n y m a n y m a n y m a n y m a n y m a n y
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Level 1
• Consolidated formation required
• Lateral access limited, but not impossible
• Production control limited (better options than with a slotted or perfed liner)
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10
101896
© 1996 Baker Hughes Incorporated
All rights reserved.
Level 1 - Open Hole Trunk
Open Hole Laterals
l Consolidated formations
l Lateral access limited
l Production control limited
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Level 2
• consolidated formations best use
• can straddle for production control
• full opening main bore
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11
101896
© 1996 Baker Hughes Incorporated
All rights reserved.
Level 2 - Cased Hole Trunk
Open Hole Junction
l Consolidated formations
l Full opening main bore access
l Lateral re-entry potential
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Level 3
• consolidated formation preferred, but completions made in unconsolidated formations
• junction is the weak point of completion
(no integrity or control)
• full bore access to main and lateral
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101896
© 1996 Baker Hughes Incorporated
All rights reserved.
Level 3 - Cased Hole Trunk
Mechanically Supported Junction
l Consolidated formations
l Noncemented junction
l No hydraulic integrity at the
junction
l Mainbore and lateral re-entry
access
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Level 4
• Consolidated formation
• mechanical supported junction
• no pressure isolation at junction - (junction is normally cemented)
• fullbore access to main, reduced lateral size (but still has full bore access).
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101896
© 1996 Baker Hughes Incorporated
All rights reserved.
Level 4 - Cased Hole Trunk
Cased and Cemented Lateral
l Consolidated formations
l Mechanically supported
junction
l No hydraulic integrity at
the junction
l Full bore access to main
bore AND lateral
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Level 5
• Consolidated or unconsolidated formation
• mechanical supported junction
• pressure isolation at junction is provided by mechanical seal (not cement)
• access preserved to main and lateral for re-entry, but may not be full-bore
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101896
© 1996 Baker Hughes Incorporated
All rights reserved.
Level 5 - Cased Hole Trunk
Hydraulically Isolated Junction
l Consolidated or unconsolidated formations
l Cement does not qualify as hydraulic isolation
l Mainbore and lateral re-entry access8/25/2015 20
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Level 6
• Consolidated or unconsolidated formation
• mechanical supported junction
• pressure isolation at junction is provided by mechanical separation/isolation
• fullbore access to main and lateral (may be two equal laterals in special case of level 6s.
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Need?
• Recognize compartmentalization
• Boundaries
– pinchouts
– faults
– folds
– inclusions
– selective chemical modification
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Oil Fingerprinting
• Every source of hydrocarbon has slightly different characteristics
• Marker materials - suggestions – carbon number plot shape
– carbon number anomalies (wax ends)
– asphaltene content, resins, etc.
• Can separate producing intervals be identified? Already been done!
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When is a compartment important?
• if it has a significant effect on recovery, then it is important.
Modeling is suggested to get to recovery numbers and decisions. You will have to make some assumptions about the connection - geologic info helps!
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1991 OB Pilot
1992 UB Pilot
Phase 1-5
Phase 6-7 Phase 10 Quads
Phase 8 Phase 10 Duals Phase 9
1991 OB Pilot Single Laterals
1992 UB Pilot Single Laterals
Phases 1-5 Single Laterals
Phases 6-7 Dual Laterals
Phase 8 Re-Entries
Phase 9 Quad Laterals
Phase 10 Dual Laterals & Quad
Laterals
$3,500
$3,000
$2,500
$2,000
$1,500
$1,000
$500
$0
0 500 1000 1500 2000 2500 3000 3500 4000
Co
st
per
Hz. M
ete
r
Fig. 7 - Drilling, Completion, Artificial Lift & Tie-in Costs 71314001.ppt
Average Horizontal Length (meters)
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FLUID
OIL
Quad Laterals
(7 wells)
Dual Laterals
(25 wells)
Single Laterals
(66 wells)
0 500 1000 1500 2000 2500 3000 3500 4000
Average Horizontal Length (meters)
Fig. 8 - Horizontal Well Fluid and Oil Rate Multiples
18
16
14
12
10
8
6
4
2
0
Hz. R
ate
/Ve
rt. O
ffs
et
Ra
te
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0 10 20 30 40 50 60 70 80 90 100
1000
100
10
1
0
Oil
Ra
te (
CD
) (m
3/d
)
Cum Oil Prod (E3m3)
Fig. 9 - Production Comparison: Single Lateral and Vertical Offset
1992 SINGLE LATERAL
191/12-18-006-13W2
1991 VERTICAL INFILL
141/14-18-006-13W2
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100
50
10
5
0.5
0.1
1
Oil
Ra
te (
CD
) (m
3/d
)
0 10 20 30 40 50 60 70 80 90 100
Cum Oil Prod (E3m3)
Fig. 12 - Production Comparison: Dual Lateral and Vertical Offsets 71314004.ppt
1995 DUAL LATERAL
191/08-28-005-13W2
1987 VERTICAL INFILL
121/14-27-005-13W2
1986 VERTICAL INFILL
141/08-28-005-13W2
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1996 QUAD LATERAL 191/14/005/13W2
1995 DUAL LATERAL 191/01-35-005-13W2
1993 SINGLE LATERAL 191/08-28-005-13W2
1986 VERTICAL INFILL 121/08-35-005-13W2
86 87 88 89 90 91 92 93 94 95 96
1000
50
10
1
0.1
Oil
Rate
(C
D)
(m3/d
)
Cum Oil Prod (E3m3)
Fig. 13a - Production Comparison: Quad, Dual, Single Laterals and Vertical Offset
71314005.ppt
5
0.5
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1996 QUAD LATERAL 191/14/005/13W2
1995 DUAL LATERAL 191/01-35-005-13W2
1993 SINGLE LATERAL 191/08-28-005-13W2
1986 VERTICAL INFILL 121/08-35-005-13W2
1000
100
10
0.1
1
Oil
Ra
te (
CD
) (m
3/d
)
1 10 20 30 40
Cum Oil Prod (E3m3)
Fig. 13b - Production Comparison: Quad, Dual, Single Laterals and Vertical Offset
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Alternatives to Multi-laterals
• fracturing
• multiple completions
• multiple wells
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Response to adding a lateral
• Depends on well placement, barriers, reservoirs, fluids and homogeneity within the compartment.
• Always question the model results. – What is the grid of the model
– what are the assumptions
– Examples………..
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An idealized reservoir
study…
Compare it with field
results.
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case 1
case 2
case 3
case 4
case 5
case 6
case 7
case 8
case 9
100 ft
200 ft
250 ft
333 ft
500 ft
500 ft
500 ft
1000 ft
Cases 2 - 9 add an extra 1000 ft to the original 1000 ft wellbore length
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Multi-laterals
• 2 to 5 legs or laterals
• legs – opposed
– stacked
– forked
– multi-planar (can be one leg)
• A “lateral” does not have to be horizontal - many, probably most aren’t.
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Considerations
• how many laterals
• need for re-entry – diagnostics
– mechanical access
– chemical access
• need for pressure seal
• wellbore stability
• lengths
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US Multi-lateral Use (1995)
• Oil 72%
• Gas 25%
• Water Flood 2%
• Gas Storage 1%
• Old numbers! - floods and thermal application increasingly use multi-laterals
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US Multi-lateral (1995)
• 2 legs - 45%
• 3 legs - 43%
• 4 legs - 9%
• 5 legs - 5%
• At this point in the development, most multi-laterals had been drilled in the Austin chalk and Baaken shale.
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Junction Design
• 1. Formation Character
• 2. Differential Pressure at Junction
• 3. Production Control Requirements
• 4. Well Path Planning
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Formation Character
• Strength - sand or shale, reactive, phase sensitive.
• Stability - both now and later
• If the rock in the junction has a sonic travel time of less than 120 u, expect junction failure on drawdown - this is an estimate from underbalanced perforating work.
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Differential Pressure
• Amount of differential - this is a minor point if the load is applied slowly, until water influx gets there.
• Shock / surge loads - this is very significant
– control?
• isolate the junction
• eliminate the surge (controlled startups at every shut down).
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Production Control
• Surge volumes, frequency, and rate of application of surge.
• downhole or surface equip. slug sensitive? Emulsions, upsets, etc. ?
• gas / water influx control needed?
• re-entry likelihood?
• abandonment concerns?
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Well Path Planning
• angle to zone
• depth
• potential for smooth turnout
• influence of other junctions
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SPE 35712 - M-L Catagories
• Draining a single layer in which areal permeability anisotrophy is critical (affects production with conventional methods).
• Draining of several stacked layers which may or may not communicate.
• Draining of several compartments which may or may not communicate.
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SPE 3712 - ML choices
• Catagories – 1. Draining a single layer in which areal permeability anisotrophy is critical
(affects production with conventional methods).
– 2. Draining of several stacked layers which may or may not communicate.
– 3. Draining of several compartments which may or may not communicate.
• Choices – option 1 favors horizontal mother bore
– option 2 favors vertical motherbore
– option 3 favor horizontal mother bore, depending on compartment location.
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SPE 35712 - ML - flow management
• Will production be commingled?
• Need of re-entry to branches.
• Downhole control needs
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ML - Advantages
• higher PI
• control for gas/water coning
• increased reservoir contact
• better chance of intersecting fractures
• better sweep potential (check alignment)
• specific EOR applications
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ML- Disadvantages
• higher initial costs
• higher risks
• candidate selection difficulties
• sensitivity to heterogenities (can be advantage)
• poor vertical perm in horizontals
• infant completion/workover/production technology
• cross flow
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Making The Opening
• Section Mill
• Whipstock / Window Mills
• Premilled Window
• Cavity Shots
• See the section on window cutting
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ML Productivity - the right choice?
• Options
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Stacked Multi-lateral
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Opposed
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Stacked and Opposed
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Forked
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Multi-planer
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Branched
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Dual Well Using "Relief Well" Intersection Technology from
Recompletion or New Well
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Opposing Laterals
• Reasons:
– Cut friction pressure losses, in wells producing at high rates.
– Position well bores to flank areas
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Opposing Laterals
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Potential Updip Completion
• Uses:
– chasing attic oil
– moving a contact away from rising water
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Isolation Potential
• Levels
– Open Hole
– Selective Isolation
– Selective Re-entry
– Full Time Isolation
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Downhole Test of Multilateral Reentry Completion: Schlumberger-Anadrill’s RapidAccess System
Conducted at Amoco’s
Drilling Technology Test Facility
Catoosa, Oklahoma
November 1997
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Test steps successfully completed
• cased a vertical well with orienting sub as part of the casing sting
• milled a window; one trip
• used gel to control debris
• drilled a lateral
• cemented a drop-off liner in the lateral
• cleaned out and retrieved whipstock from main wellbore
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RapidAccess System Schlumberger-Anadrill
Lateral completed open hole or with liner
Orienting sub (keyway)
Up to 3 laterals can be drilled, each with different keyways, which allows selective reentry for stimulations or other workovers
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Control within the lateral
• Profiles and sleeves
• ECPs at strategic positions
• Hydraulic flow control
• Screens and liners
• Most operations depend on ability to enter the lateral.
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Lateral placement?
• location of contacts
• thickness of zones
• relationship to kickoff point
– departure angle
– dogleg angle
– re-entry needs
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Well path based on geologic
information.
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Completion ability an issue too
• Must be able to get the completion into place
• Can it be kept on line and producing steadily?
• re-entry?
• isolation?
• Plug and Abandonment?
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One of many proposed lateral entry control systems – all are expensive and few are well proven.
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There are many sketches of lateral exit windows; and most have window debris that make exit and return very difficult.
The typical window is from 10’ to 20 ft in length (casing length opening).
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Lateral Re-Entry Needs
• 1. Logging the lateral
• 2. Lateral shutoff
• 3. Stimulation
• 4. Cleanout
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Alaska Multi-lateral Well Interventions
Taylor West
PE
GPB Orion / Polaris
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VO Producer Design • Production Interval:
– 6-¾” production holes with 4-½” slotted liners or 4”x 4.8” Screens
• Completion Design: – 4-½” tubing with GL artificial lift
and Jet Pump back-up via sliding sleeve
• Functionalities: – Monobore design
– Mechanical integrity at window
– Thru-tubing access to all laterals
– Selective lateral isolation
– Selective lateral access using diverter or MLT tool
Lateral Entry Module (LEM)
LEM
Diverter and Isolation Sleeve
Lateral DiverterLateral
Isolation Sleeve
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ML Interventions Challenges & Checklist
• GPB uniquely positioned to lead effort due to access
• Current design ~ 3 yrs old
• Limited experience – mixed success
• Risk to high value wells discourages “testing”
• Need to test Baker component functionalities
• Need to test access / logging technologies
• Need to develop new techniques & tools
• Need to build confidence with town & wells group
Well Management Masterclass, Oct 30-Nov 3, 2006
Preparations
– Intensive focus from Wells Group CTU PEs
–iCoil installed in 1-3/4” service coil w/ straightener
–Bench tested all BHAs through model junction
–Incorporated learnings from Milne & West Sak interventions
Activity
Kit Functionality:
Diverter Set
Diverter Pull
Isolation Sleeve Set
Isolation Sleeve confirm full shut-off
Coil transit / work through sleeve
Sleeve Pull
Motherbore memory logging
Motherbore FCO /Stim
Use Mainbore centralizer (coil / PL tools)
Open Mainbore Shear Disk
Able to reach TD in Laterals
Mainbore IBP located on junction
Work through Diverter:
1-3/4" Coil entry through Diverter
Confirm CoilCade modeling for Depth reached
I-Coil DSP (real-time CCL/Temp/Press)
I-Coil DTS - flowing & pump-in
Downhole fluid sampling
memory tools - surveillance & diagnostics
FCO w/ carrying fluids
Simple Stimulation (Diesel/Xylene)
E-line Tractor Production logging, WFL
Diagnose / Identify water entry along a lateral
Shut-off water entry along a lateral
Discovery Tool Lateral Access w/o diverter:
Shop Testing through junction
Jet Blaster for slot cleaning & FCO
FCO w/ carrying fluids
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CTU ML Interventions Key learnings
Significant FEL - early Wells Group engagement gave ownership
Drift / wash runs ensure success in running full-diameter components
Not easy to stay in the mother bore
Not a smooth design – lips, ledges (mostly at windows)
No significant fill evident in laterals
New surprises on previous givens – PPROFs – slick is best!
Pipe straightener – limited additional depth reached (+300’)
Metal-to-metal lubricants extended coil reach 3000’+
ML checklist items
Proved worth of iCoil – knowing where you are (ccl), pressure, temp
Diverter set / transit w/ tools / retrieved
Sleeve set / transit / confirmed sealing / pull
Lateral entry / Sample / FCO / Stim
MLT “Discovery Tool” lateral entry – 1st successful run in this completion design
Mainbore and lateral logging – ID water and gas entries
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Well Management Masterclass, Oct 30-Nov 3, 2006
Technologies
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Well Management Masterclass, Oct 30-Nov 3, 2006
Learnings
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Problems in Re-Entry
1. EOT location relative to junction 2. Making the corner 3. Stiffness of tube 4. Departure angle 5. Junction shape
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Solutions in Re-Entry
1. “poke and hope” 2. bent face 3. bent face and motor 4. “gate” products a. whipstocks b. selective ramps / lugs or profiles
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Can you be sure where you are?
1. Pipe depth measurement 2. MWD tools 3. Conformance to model prediction 4. End of the lateral measurement 5. Others?
?
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