WELL COMPLETION OBJECTIVES AND DESIGN Lecture #1
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WELL COMPLETIONOBJECTIVES AND DESIGN
Lecture #1
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Learning Objectives
• Define completion objectives and constraints
• Identify key data requirements
• Define functional capabilities of well
• Create completion sketch and identify key components
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Agenda
• Completion objectives
• Discussion of key design decisions
• Conceptual well design
Bottomhole completionSelection of production/injection conduit
Well functionality definition
Preliminary location of components
Well performance consideration
• Generic completion review
• Interface between Drilling and Completion
• Review example completions
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Completion Objectives
• Effective reservoir exploitation
Control fluid entry/exit, rates & recovery
Manage pressure depletion
Control zonal contributions• Minimize total cost over the life of the well
• Ensure safe operation/well control
• Incorporate flexibility to adapt to changing conditions
• Facilitate intended workover strategy
• Document strategies/decisions/experiences
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Economic drivers for Design
• Optimal combination of
Initial capital investment
Operating Costs
Intervention Costs Abandonment Costs
• Life of well/field?
Can be a significant driver
Normally intended as 12-30 years in the firstinstance, but it varies from <1 to >50 years!
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Constraints on Design/Completion
• Data – usually incomplete and of variable quality
• Logistics
Location/environment/topology – access issues
• ProcurementDelivery/supply dates
Inventory – availability & stock control
Bulk discounts
Preferred vendor?
• Availability of service centre support
• Contractual obligations with vendor
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The Design Process evolves over the life
of well
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Establish Design Criteria
Preparation of Production Zone
The mechanical Completion Design and
installation of completion String
Production Initiation and Remedial
Measures
Monitoring Well and Completion
Performance
Update
Design
Criteria
Workover
INTEGRATION OF THE WELL COMPLETION PHASES
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Phased development of completion strategy
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Budget Costing
Internal AFE approval
Partner Approvals
Regulatory approvals
Conceptual
Design
Design Phase Objectives/use Key outputs Constraints
Lift decisions
Flowrates / nominal tubing
size(s)
Bottomhole completion
Tubing/casing/annular flow
Identify operational ricks
Limited well data
Understanding of
heterogeneity?
Resource constraints
Final
Design
Rigorous and optimised
design
Optimised - technically
and economically
Offload and cleanup
proceduresWell integrity assurance
Safety case(s)
Running procedures
Test and verification
Contingencies
Equipment procurement –
specifications & sourcing
Running procedures and
programme
Fluids and additivesContingencies
Documentation and testing
requirements
Data limitations –
quantity and reliability
Future forecasts
Vendor performance
Alternative
investments?
Oil price uncertainties?
Equipment longevity
and reliability
Continuous
validation,
enhancement and
modification
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Conceptual design – influential issues and decisions
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Context of well
Conceptual Design Considerations
Specification of Design
Geographical
location
Land or
offshore based
Fluid type &
contaminants
Artificial lift
requirements
Well trajectory
or orientation
No. / thickness
of zones
Geo-political risks,
accesses, services
Physical access, subsea
or platform
GOR/LGR
H2S/CO2 content
Timing
Gas/power availability
Reliability
Flow capacity/stability
Reservoir management
Intervention
Relative depletion
Crossflow
Complexity/cost
Bottomhole
completion
Production
conduit
Preliminary
flow capacity
Completion
functionality
Barrier and
Integrity
requirements
Openhole
Uncemented liner
Cemented Casing
Casing flow, tubing
and/ or annular flow
IPR & TPR
Initial tubing size
recommendation
Retrievability,Monitoring
Circulation
Well closure
capability
Backups
Number of barriers
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Open Hole – “Barefoot completion”
• Advantages
Low cost
Faster getting well online
Easily deepened retrospectively
PI? – maximum r w
• DisadvantagesWellbore stability?
Reservoir management?
Poor isolation of water and gas
Minimal production/injectionselectivity
• Applications
Low cost area
High well count
Naturally Fractured reservoirs
Geometrically complex wells
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Uncemented Liner/Screen completion
• Advantages
Lower cost
Supports borehole stability
Sand exclusion – either with astandalone screen or gravel pack
• Disadvantages
Non-selective hydraulic access toreservoir
Remedial options
Reservoir management?
Limited due to complications createdby annulus behind screen
• Applications
Unstable wellbores
Sand Production?
Can use swell packers or ESPs toimprove selectivity/operability ofcompletion
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Production Conduit Options
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Casing Flow (Tubingless / no tubing)
• Advantages
Low cost
Shorter completion – accelerated production
Large wellbore – minimum friction
• Disadvantages
Casing integrity?
Corrosion
Erosion
Pressures
Backup or retention?
Slippage leading to slugging/loading – stableproduction over the life of the well?
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Casing and tubing flow – no annular isolation
• Advantages
Lower cost
Large wellbore – minimum friction
3 optional flow cross sectional areas – improved
stability? – greater ability to handle slippage• Disadvantages
Casing integrity?
Corrosion
Erosion
Pressures
Backup or retention?
Limitations on flow stability/flexibility
Annulus heading when annulus not flowing
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Tubing Flow with Annular Isolation
• Advantages
Annulus/casing protected – enhanced wellbore
integrity
Hydraulic backup – containmentImproved well and flow control
• Disadvantages
Higher cost
Limitations on wellbore cross-sectionRequires circulation capability
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Well Control – Barrier Policy
• What are barriers?
Capabilities to hydraulically isolate reservoir from
atmosphere/surface
• OptionsHydraulic – column of kill weigh fluid
Mechanical – valves, plugs etc
• Recommendation?
Minimum of two specified for most operationsPrefer minimum of 3 for most situations
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Subsurface Barriers
• Surface Barrier – Pressure and flowContainment – BOPStack or Xmass Tree
• EmergencySubsurface Closure
– SSSV
• Annular isolation –
Packer
• Plug tubing andprotect the reservoir
– Deep-set nipple
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Well Design – Well Functionality/Operability
• Well functionality requirements
Well isolation – barriers?
Well control/offload
Prefer to circulate rather than bullhead
Circulate as deep as possible in order to
Minimize kill fluid density Minimize hydrocarbon inventory in well
Monitoring
How and what is to be monitored?
Value of information?
Interventions?
Strategy/access/costs
Maximize reliability?
Duplicate critical devices?
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IPR for Pwf above the Bubble Point
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PI = Straight line IPR
Productivity Index (PI also
given as J)
Pwf = Pr – Q/PI
or Q = PI * (Pr -Pwf )
or PI = Q / (Pr – Pwf )
PI is given in units of pbd/psi
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Pwf below the Pbubble point : Vogel IPR relationship (1968)
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Vogel developed this
IPR relationship by
best fit fromnumerous reservoir
simulation runs
Vogel has a long
history of use with
good success
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Gas Well inflow: Steady/Semi Steady State
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Q = C (Pr
2
-Pwf
2
)n
Bureau of Mines IPR, a.k.a., Back Pressure Equation
(Rawlings & Schellardt 1936)
Exponent ranges from 0.5 to 1.0; should be 0.92 – 0.95
Exponent derived from multiple rates by plotting (Pr 2 - Pwf
2)Versus rate and finding n, the inverse of the slope
Then, “C” found by substituting one test point into the formula
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Non-Linear IPR (Gas)
• In high rate wells turbulence can occur in the near
wellbore
• Pres2 – Pwf
2 = aq + bq2
Where
- aq = pressure drop due to laminar (Darcy) flow
- bq2 = pressure drop due to turbulent (non-Darcy)
flow
The constants a and b can be derived from multi-rate welltests or alternatively estimated from known reservoir and
gas properties.
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Inflow Performance Relation - IPR
• Defines reservoir deliverability• IPR = Q vs Pwf for Oil well above PBPT
• Straight Line IPRRate ∞ Pressure Draw Down in Reservoir
Constant of Proportionality = Productivity Index, J
J=PI=Q/ΔP
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Radial inflow and pressure drop
Radial convergence results in
acceleration and rapidly
increasing pressure drop as you
approach the sandface
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Components of Tubing pressure Loss
• dPTBG=dPHHD + dPFRICT + dPKE
dPTBG=Total tubing pressure loss between surface and
bottom of tubingdPHHD=Hydrostatic head pressure loss in tubing (“weight
of vertical fluid column”)
dPFRICT=Frictional pressure drop in tubing
(“interaction/drag with tubing wall”) dPKE=Kinetic energy loss (“acceleration and
deceleration”)
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Production Optimization
• Variables affecting Optimum Production Rate
Tubing Head Pressure
Water Cut
GOR
Inflow performance
Tubing Size
Wellhead / choke performance
• IPR-TPR curves assesses sensitivity to the abovevariables to predict optimum production rated under
various conditions
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Effect of changing water cut
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Generalized Tubing Completion
W.E.G.
Well Head
Xmass Tree
S.S.S.V.
Nipple
Side Pocket
Mandrel
Sliding SideDoor
Seal
Assembly
Packer
Nipple
Perforated
Joint
Upper
Wellbore
Completion
Lower
WellboreCompletion
Flow control and Isolation
Tubing & Casing, Suspension, NippleUp, Xmass Tree, Annulus Access
Safety Isolation
Circulation or Fluid Injection
Circulation
Accommodate Tubing Movement
Annular Isolation
Tubing Isolation
Flow alternative Entry
Landing gauges
Wireline Re-entry
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Function of the Wellhead
• Suspend casing strings and production tubing as the
well is sequentially constructed
• Allow “nipple up” (physical connection) of upper flow
control / barrier system
BOP stack while drilling and during workovers
Xmass tree for production / injection phases
• Allow hydraulic access to the annulus between the
tubing and casings
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Basic Spooled Wellhead and Tree
• Xmass Tree
• Adaptor Spool
• Wellhead
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Subsurface Safety Systems
• Function?
Emergency closure of well if primary barrier fails
• Functional valves types
Tubing safety valves Annular safety valves
Injection safety valves
• Operability
Remotely controlledDirectly controlled
• Retrievability
Tubing, CT or WL retrievable
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Tubing Subsurface Safety Valves
• Remotely controlled
Failsafe
Hydraulically
operatedTR-tubingretrievable
WL-wireline
retrievableStandard methodsto test operability
• Directly Controlled
Subsurfacecontrolled
Can be set at anydepth
Easily replaced
Design operating
conditions must beroutinely reviewed
Testing?
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Remotely Controlled SSSV
Surface Controlled
Sub Surface Safety Valve
flapper is held open by hydraulic pressure
valve fails to closed position by spring
a “tubing retrievable” surface controlled
sub surface safety valve (SCSSSV) is run in
well on production tubing
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Circulation Capability / Devices
• Purpose?
Tubular
displacement
Kill the well
Offload the well
Fluid injection
Gas liftChemical injection
• Options:
Sliding side Door
SSD
Side Pocket MandrelSPM
Ported Nipple
Tubing Punch
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Type XO Sliding Side Door
• Upper nipple profile
• Inner sleeve slots
Upper
Lower
• Outer sleeve ports
• Packing between
inner and outersleeves
• Lower seal bore
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Nipple –Lock Mandrel Systems
• System allows:
Installation and retrieval of devices for:
Flow control
Flow regulation Flow monitoring
• Nipple provides location to :
Suspend flow control device in well – profile
Seal device in tubing – seal bore• Lock Mandrel provides:
Ability to suspend flow control in nipple profile
Seals on mandrel engage nipple seal bore
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Flow Coupling• Flow Coupling assists in
tolerating internal erosioncreated by converging ordiverging flow
• Flow coupling is a short piece
of pipe which has a wallthickness greater than thetubing string. Flow couplingsare used to delay erosionalfailure at points inside acompletion string, where
turbulent flow is expected tooccur
• Downstream location – moresevere erosion location
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Reasons for using a Packer
• It protects the casing from reservoir pressure andproduced fluid
• Isolates casing leaks or squeezed off perforations
• Isolate between multiple producing horizons – preventcrossflow
• Eliminate or reduce pressure surging or annulus heading
• Hold kill fluid in the annulus
• Preferred for certain artificial lift methods –gas lift
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Retrievable Packer
• Hydraulic Hold-down
• Packer seals
• Lower slip system
• Slip release system
• Release section
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Tubing to Packer connection Systems
• Function?
Accommodates tubing stress
Allows disconnection/retrieval of the upper completion
from and without pulling the packer
• Options?
On-off tools
Anchor/latchDynamic seal systems
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The Drilling and Completion Interface
• Well trajectory and configuration
•Critical role of casing/liner cementation
• Avoidance of permanent damage
• Critical opportunities for optimisation/enhancing well“value”
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Well Configuration
• Influential factors
Costs
Complexity
Standardization of equipmentInventories
Bulk purchasing
Geological uncertainties – contingency
requirements• Impacts
Upper wellbore clearances
Tubular sizes versus pressure loss
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Casing nomenclature
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Drill-in fluids
• Objectives is low damage drilling of the pay zone
• Wide choice of fluid options
Low solids OBM
Sized saltSized carbonate pills
HEC pills
Water foams
Base oils- all fresh mixed to drill zone
• Selection is mostly by operator preference and
experience
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Fluid Loss Control Options
• Base get fluid
Removal by breaker?
• Particulate additives – borehole wall filtercake
Calcium carbonate
Ground salt
Oil soluble particles
Resins
Wax beadsetc
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Filter Cake Removal
• Controlling factors
Thickness and permeability of cake – depend on
time and overbalance pressure
Ability to apply drawdown? –
vertical/horizontal/multilateral
Avoid flowback through screen if possible
Must be specially designed to facilitate cleanup
•Lift pressures
Dependent on fluid
Contamination with cuttings
Impact of long lateral?
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Casing Nomenclature and T.O.C.
• TOC?Normally preferred as
high as possible
Prefer to cement backabove previous casing
shoeConstrained by:
Depth
Temperature
Pressure
TimeFormation frac
pressures andpermeability
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Objectives of Primary Cementing
• Complete Cement Sheath without mud or gas
channels
• Cement bonded to Formations
• Cement bonded to Casing
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Critical Features of liner Cement Job
• Small Clearances: usually <<3 in.
• Decentralized and often inclined
• Smaller Length: 100-500 ft overlap with previous shoe
• Batch Mix cement to homogenize
• Potential leak into annulus via liner lap: impact on
barrier policy?
• Debris potential in top of liner
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Liner Cementation
• DP running string
• Single plug released
by dart/inner plug
• Critical to long term
integrity
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Tubing Completion Configurations
• Casing completions
• Conventional packerless tubing
• Tubing - packer completions
• Monobore
• Tubingless
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Basic Natural Flow Completion
• Tubing – carries fluid to surface
• Subsurface safety valves – shut in wellin an emergency
• Side Pocket Mandrels – Circulationbetween annulus and tubing (gas or
chemicals)
• Circulation Device (SSD) – communication between tubing andannulus
• Packers – isolate production zones
• Nipples – installation of flow controlcapabilities
• Flow Couplings – protect tubing frominternal erosion
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Big Bore Producer or Injector
• Big bore
producer or
injector
• Permanent
packer in liner
• Two section
completion
Liner
Casing
Tubing
WL Operated SSD
Extralong Tubing Seal assembly
Permanent Packer Wireline Set
Millout Extension
TailpipeNipple
Perforated flow TubeLanding Nipple
SSSV
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Monobore Completion
• Monobore
• Facilitates
concentric access
• Big bore – low
pressure los
• Cannot circulatebelow liner hanger
without tubing
(CT)Liner
SSSV
Tubing
SPM (Side Pocket mandrel)
Polished Bore Receptacle
Liner Packer & Hangar Assay
Nipple
Casing
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“Tubingless” Completion
• Simple, low
cost
completion
• Integrity?
• Intervention
options?
Casing
Wireline Isolation Nipple
Direct Controlled SSSV
Borehole Wall
Direct Controlled SSSV
Lower Zone Perf
Direct Controlled SSSV
Cement
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8/13/2019 Lecture+#1 Well+Completion+Objectives+and+Design
http://slidepdf.com/reader/full/lecture1-wellcompletionobjectivesanddesign 73/73
Summary
• Start with “basis of Design” statement
• Keep it simple and fit for purpose
• Consider
• Uncertainties
• Costs
• Operating and workover costs
• Longevity requirements
• Learn from the design process - documentation