Well completion is the process of preparing a drilled well for production, involving various methods and equipment based on multiple factors like wellbore properties and fluid characteristics. The document outlines completion types such as open-hole, cased-hole, and monobore, along with their advantages and disadvantages, and discusses strategies for sand control and artificial lift systems. Additionally, it highlights the significance of intelligent well systems for real-time reservoir management.

1. Well Completion
Well Completion is the process of preparing a well for production.
The completion program is implemented when a well has been
drilled to the final objective depth and potential pay zones
identified and evaluated as being of commercial value.
Completion methods and equipment are varied. Choice
of an appropriate system depends on:
• Size and orientation of the wellbore
• Physical properties of the hydrocarbon-bearing rock
• Number of pay zones
• Nature and properties of the fluid to be produced
• Anticipated rate of production
• Cost
• Life cycle considerations

2. Basic Completion
Equipment Terminology
Tubing hanger
Tubing spool
Surface Controlled
Subsurface Safety
Valve (SCSSV)
Gas lift valves
Production casing
Production packer
No Go Nipple
Re-entry guide
Blast joint
Seal bore extension
Seal assembly
Production tubing
Flow coupling
Landing Nipple
Circulating sleeve

3. Completion Types
1. Open-Hole Completions
2. Cased-Hole Completion Types
• single zone completion
• single tubing w/ multiple
selectives
• dual tubing strings
• dual tubing strings w/ sand
control
3. Monobore Completions
4. Sand Control
• gravel packs
• frac packs
4. Horizontal Wells
• open hole, slotted liner, cased
5. Multi-Laterals
• TAML Levels
6. Intelligent Well Systems
7. Artificial Lift Systems
• beam (rod) pump
• gas lift
• electric submersible pumps (ESP)
• progressive cavity pumps (PCP)
• jet pump
• plunger lift

4. Open-Hole Completion
Intermediate casing is set at the top of a
producing zone, then the wellbore is drilled
into the producing / injection zone but no
production casing is set lower. Used
primarily in highly competent or “hard
rock” formations.
Can be used in vertical, deviated, or
horizontal wells.
Advantages
1) Adaptable to special drilling techniques to
minimize formation damage.
2) Prevent lost circulation into production zone.
3) Excellent gravel pack candidate where
productivity is important.
4) No perforating expense.
5) Log interpretations not critical.
6) Full diameter opposite pay zone.
7) Can be easily deepened.
8) Easily converted to liner or perforated
completion.
9) Generally applicable in homogeneous carbonate
reservoirs.
Disadvantages
1) Excessive gas / water production
difficult to control.
2) Selective fracing / acidizing is
difficult.
3) May require frequent clean out.
4) Casing set “in the dark.”
5) Limited variety of production tools
available.

5. Casing is set through target formation, cemented, and
then perforated. Used for less competent or “soft
rock” formations. Most flowing wells are completed
with this method.
Used in vertical, deviated, or horizontal wellbores.
Advantages
1) Excessive gas / water production easily
controlled
2) Can be easily stimulated
3) Adaptable to multiple zone and zonal
isolation
4) Easily adaptable to specialized sand
control and selective fracturing &
acidizing
5) Wide variety of production tools available
6) Good method to minimize workover and
well cleanout costs.
Disadvantages
1) Risk of formation damage is greater
2) Primary and remedial cementing is
critical
3) Log Interpretation critical
4) Higher capital costs
Cased-Hole Completion

6. Single Completion
Single Tubing String
• Used in all wellbore types
• Easy to operate, optimize and
manage artificial lift methods
• Provides well control
• Cheapest method when
commingling multiple zones
(no Reservoir Management)

7. Single tubing with multiple selectives
This conventional single provides the
opportunity to perform slick line plug
backs instead of a workover operation.
Typically the zones are perforated with
casing guns prior to running the
permanent or hydraulic set production
packers.
Use wireline plugs set in landing
nipples to isolate zones from bottom
up. Can use sliding sleeves to control
flow from simultaneous producing
zones.
Zone C
Zone A
Zone D
Zone B
Packer
Sliding
sleeve
Landing
nipple
Blast
joint

8. Dual Completion
Dual Tubing String
• Used in all wellbore
types, but more difficult
in open hole completions
• Provides well control
• Provides Reservoir
Management
• Prevents multiple zone
cross flow and fluid
incompatibilities
• More difficult to operate,
optimize and manage
artificial lift methods

9. Dual Tubing String Conventional
Two tubing strings that may or may not be the same size
provide a dual cash flow. Gas lift is more difficult to apply to a
dual and workover frequency & costs are typically higher in a
dual than a single or single selective.
Dual Tubing Strings with Gravel Packed Zones
This design combines the sand control method with the
previously mentioned issues of dual tubing strings. Another
method would be similar to the single selective to only gravel
pack one of the zones. Note that only the lower zone can be
accessed for through tubing repair work.
Dual Tubing String

10. Monobore Completions
A completion that utilizes a production tubing and casing string with a
uniform inside diameter (ID) from top to bottom, including the
formation. This facilitates the running and setting of tubing
intervention devices (plug, pack-offs, etc.) across pay intervals.
• Advantages
– Lower cost than conventional wells
– Future well work can be accomplished without killing the well, thus
reducing the chance of reservoir damage
– Future well work is accomplished by using either coil tubing and/or
wireline units
– Eliminates the need, risk and cost of stacking multiple selective
completions
• Disadvantages
– Smaller ID across the pay interval limits remedial options (e.g. sand
control, abandoning perfs, water and/or gas shut-off, etc.)

11. Monobore Completion
Monobore completion with large
diameter tubing string for high
production rate wells
Safety Valve
Seating Nipple
4 1/2" Tubing
Gas Lift Mandrel
9 5/8" Casing
Production Packer
7" Production Liner
4 1/2" Production Casing
Seating Nipple
W/L Entry Guide
Liner Crossover
Liner Hanger

12. Methods of Sand Control
• In-situ consolidation (resin or “plasticizing”)
• Screens (wire wrapped, mesh, pre-packed)
• Gravel Pack (open-hole or cased-hole)
• Frac Pack (cased-hole)

13. Resin Consolidation
• Inject resin
• Below frac pressure
• Zone coverage
• Limits
– short intervals
– small rathole
– coiled tubing placement
is best method
Formation Resin
Casing
Area

14. Gravel Pack Placement
Open-Hole:
Fill the Screen/Openhole
Annulus

15. Gravel Pack Placement
Cased-Hole:
• Fill screen/casing annulus
• Pack the perforation tunnels

16. Hydraulic Fracturing (stimulation)
• Improves flow path into the
wellbore
• Redistribute the stresses
• Lower the velocity of the
reservoir fluids... lessening
migration of fines
Damaged
Area
Damaged
Area
Borehole

17. Hydraulic Fracturing (stimualtion)
• Improves flow path into
the wellbore.
• Connect layers to the
wellbore.
• Redistribute the stresses.
• Lower the velocity of the
reservoir fluids...
lessening migration of
fines.

18. Horizontal Wells
A “horizontal well” or high angle well describes a well drilled
at an angle greater than 70º relative to vertical.
• Can connect natural fractures in carbonates.
• Prevent water/gas coning by reducing pressure draw down.
• Improves sweep efficiency through infill drilling, horizontal
injection for waterflood or EOR.
• Can enhance property value by increasing recovery in tight
gas reservoirs or thin sands or low permeability reservoirs.
• Location constraints limiting numerous wells.

19. Horizontal Open-Hole Completions
– Advantages:
• Higher Productivity
• Delay Water Production (shorten field life)
• Less Susceptible to Completion Damage
• Reduce number of wellbores for reserves recovery
• Lower Completion Cost
– Disadvantages:
• Difficult to Isolate Extraneous Fluid Production
• Multi-Zone Completions More Difficult
• Exposed shale intervals can cause problems

20. Horizontal Well Open-hole
Reservoir characteristics that
favor this completion
• Vertical permeability greater
than 50% horizontal
permeability
• No inter-bed barriers or
sealing laminations
• Stable formation or plan for
sand control
• Good bottom water control
• Confined surface and
reservoir access
• Fracture treatments possible,
but difficult

21. Reservoir characteristics that favor
this completion
• Vertical permeability greater
than 50% horizontal
permeability
• No inter-bed barriers or sealing
laminations
• Some sand production or plan
sand control
• Limited bottom water control
• Confined surface and reservoir
access
• No fracture treatments
Horizontal Well Open-Hole with Slotted Liner

22. Multi-Lateral Wellbores
• Reservoir Characteristics that
favor this completion
– Surface/reservoir access
limited
– Thick layer pay zones
– Multiple well types needed
– Compartmentalized reservoirs
– Wellbore placement needed
for sweep/drainage
– Limited access for future work

23. Drivers of Multilateral Technology
• Cost reduction
• Slot conservation
• Increased reserves
• Accelerated reserves
• Delineation of the reservoir

24. Intelligent Well Systems (IWS)
An Intelligent Well System is defined by ChevronTexaco
to include at least one downhole flow control valve, one
downhole sensor, and two distinct intervals.
Provides real-time reservoir management:
• Downhole data sensing, acquisition, and transmission
of temperature, pressure, density, flow, etc.
• Remote control of flow and well operations

25. Beam Pump (sucker-rod pump)
Mechanics
• Utilizes a reciprocating rod to move a
downhole pump.
• Downhole pump consists of “traveling”
and “standing” valves, which utilize
check valves to trap and mechanically
lift a column of fluid.
Characteristics
• Comprised ± 80% of all artificial lift.
• Predominantly land use.
• Handles gas and solids fairly well.
• Best for low-volume producers (5 to
5,000 BFPD)

26. Gas Lift
Mechanics
• Best mimics “natural” flow. Utilizes
pressurized gas injection downhole to lighten
the hydrostatic “head” of a column of fluid,
allowing reservoir pressure to lift the fluid
column to surface.
• Uses downhole valves to regulate the amount
and depth of gas injection
• Continuous or intermittent lift.
Characteristics
• Used wherever a gas source is available.
• Second most common lift system (Most
common offshore lift system).
• Good handling of solids.
• Wide range of production rates

27. Electric Submersible Pump (ESP)
Mechanics
• Utilizes a downhole electric motor to drive a
downhole centrifugal pump.
• Uses surface electrical transformers and
variable frequency speed drives to deliver
consistent power.
Characteristics
• Requires electrical power supply.
• Highest lift efficiency of all lift systems.
Becoming more common as an offshore lift
system.
• Poor handling of solids and fair handling of
gas.
• Wide range of production rates (200 to
30,000 BFPD)
• Lifespans anywhere from 1 to 7 years
depending on environment and
horsepower/power quality.