well completion basics

1. WELCOME TO
BASIC DRILLING COURSE
Well completion

2. Oilfield Life Cycle
Exploration Drilling Completions Production Abandonment

3. Well completion
is the process of making a well ready for production (or injection)
after drilling operations. This principally involves preparing the
bottom of the hole to the required specifications, running in
the production tubing and its associated down hole tools as well
as perforating and stimulating as required. Sometimes, the
process of running in and cementing the casing is also included.
After a well has been drilled, should the drilling fluids be removed,
the well would eventually close in upon itself. Casing ensures that
this will not happen while also protecting the wellstream from
outside incumbents, like water or sand.

4. WELL COMPLETION
WC is the “hardware” of the outflow system & final stage of a
drilled well.
The design philosophy of WC is to “Maximize Profitability”.
 by maximizing well hydrocarbon recovery.
 by considering the full hydrocarbon resource life cycle.
Quality concepts for WC is;
“A Quality Well is a well which contributes, over its life cycle,
maximum monetary value, without compromising safety &
environmental standards”
Completion: is the general name for the equipment that is placed in
the well after the drilling phase in order to enable the well to be
brought into use as a producer or injector well. Completion
equipment comprises the completion string with its individual
components, and the Xmas tree at the top of the well.

5. COMPLETION functions
1- Install the tubing.
2- Optimize flow.
3- Protect the casing.
4- Contain the reservoir.
5- Enable tubing to casing circulation.
6- Enable chemical injection.
7- Enable well kill.

6. Well completion
1- Lower completion (downhole completion)
2- Completion components
3- Perforating and stimulating

7. 1- Lower completion (downhole completion)
Type of Completion include:
 Natural Completions
Natural completions are those in which little or
no stimulation is required for production.
Sandstone and carbonate systems with
good permeability and mechanical stability are ideal for natural
completions.
 Stimulated Completions
These completions are generally applied to improve the
natural drainage patterns of hard, low-permeability
formations. It is used to remove barriers that
prevent easy passage of fluids into the wellbore.
 Sand-Control Completions
Sand-control completions support the formation while
allowing the flow of fluids. They are performed in
young, unconsolidated or less mechanically
competent sandstones

8. 1. Producer Well
2. Injector Well
3. Observation Well
4. Kill Well
The well is either Vertically & Horizontally completed.
 Open Hole Completion
 Un-cemented Liner Completion
 Gravel Pack / WWS Completion (Pipe with openings Wrapped With
Screen).
 Tubingless Completion
 Cemented & Perforated Completion
 Single String or Multiple String Completion
 Convectional or Monobore Completion
1- Lower completion (downhole completion)
Well Completion Types

9. 1- Lower completion / Well Completion Types
1. Conventional Completion (Longer Duration)
2. Mono-bore Completion (Shorter Duration)
“Completion with fullbore access across the payzone without diameter
restrictions”.
◦
◦
◦
◦
▪▪
CONVENTIONAL Mono-bore
Same tubing ID
WRSV
TRSV
SSD
SPM
Bottle Neck
No Restriction
Minimize annular “waste” (swedge ▼or run Liner)
Omit, use CT well servicing
Omit or use slimline SPM
Use full bore slimline tubing run SSSV
Use TCP or CT run guns

10. 1- Lower Completion / Completion Type (3)

11. 1- Lower Completion / Completion Type (4)

12. 1- Lower Completion / Completion Type (5)

13. 1- Lower Completion / Completion Type (6)

14. 1- Lower Completion / Completion Type (4)

15. Well Completion design is dictated by the type of well to be completed.
1. Producer
2. Injector
3. Kill
4. Observation
The 3 considerations of designing well completions are;
1. Inflow system
2. Outflow system
3. Number of zones to be produced
WELL COMPLETION design

16. 1. Inflow system - VERTICAL
OPEN HOLE
SLOTTED
LINER
WWS or
PREPACK
SCREEN
GRAVEL PACK
Technological advances allow boosting of the well inflow to a considerable
extent – albeit at a cost.

17. 1. Inflow system - VERTICAL
STD CEMENTED &
PERF PROD CASING
INTERNAL GRAVEL
PACK

18. 2. OUTFLOW – PRI RECOVERY
It’s essentially a conduit with flow controls & where necessary artificial lift or
pressure boosting facilities.
TUBINGLESS
With out tubing.
HIGH PRESSURE
Cemented, perforated &
completed with tubing &
accessories.
Low pressure gas reservoir
MONOBORE
With high rate liner
Restriction Free
Susceptible for WI

19. 2. OUTFLOW – SEC RECOVERY
Pumping Unit
Production Casing
Tubing
Gas
Gas Anchor
Oil
Operating Fluid Level
Tubing Anchor
Sump
Perforations
Plunger
Pump Barrel
Travelling Valve
Stationary Valve
Sucker Rod String
ROD PUMPING
HYDRAULIC PUMPING

20. 2. OUTFLOW – SEC RECOVERY
Operating
Gas Lift
Valve (OGLV)
Gas Supply
Control And
Metering System
Unloading
Valves
Unloading
Valves
Continuous
Gas Lift
Standing Valve
Intermittent
Gas Lift
Motorised
Flowline Valve
Water Oil
Gas
Surge
Tank
Manifold
Compression
GAS LIFT

21. 3. PRODUCING ZONES – SINGLE
Single
Completion
Single
Selective
Interval
Single
Selective
Interval
Single
Commingle

22. 3. Producing Zones – Multiple
Multiple
Completion
Concentric
Completion
Multiple
Commingle
Completion
Multiple
Selective
Completion

23. 2- Completion equip (components).
It is the hardware of the outflow system.
There many different types & functions of downhole
accessories installed in a the outflow system depending on the
type of a well.
It is essentially important to understand these accessories prior
doing well operations.

24. 2- Completion equip (components).
 Wellhead.
 Christmas tree.
 Tubing Hanger.
 Production Tubing.
 Down Hole Safety Valve (DHSV).
 Annular Safety Valve.
 Side Pocket Mandrel (SPM).
 Electrical Submersible Pump (ESP)
 Landing nipple
 Sliding sleeve (SSD)
 Production Packer
 Down hole Gauges
 Perforated Joint.
 Formation isolation valve.
 Centralizers.
 Wireline Entry Guide.

25. 2.1 Wellhead
It’s a built up of modules. During drilling BOP is installed above it.
It must be removed each time a new module to be installed &
replaced the BOP on top of it before commence drilling.
Features:
1 Starter Spool (Conductor Pipe)
2 Surface Casing Head
3 Surface Casing Hanger
4 Production Casing Head
5 Production Casing Hanger
6 Tubing Head
7 Tubing Hanger
CONVENTIONAL WELLHEAD

26. 2.1 Wellhead / Components
 The primary components of a wellhead system are:
 casing head
 casing spools
 casing hangers
 choke manifold
 packoffs (isolation) seals
 test plugs
 mudline suspension systems
 tubing heads
 tubing hangers
 tubing head adapter

27. 2.1 Wellhead / Functions
 A wellhead serves numerous functions, some of which are:
 Provide a means of casing suspension. (Casing is the permanently
installed pipe used to line the well hole for pressure containment
and collapse prevention during the drilling phase).
 Provides a means of tubing suspension. (Tubing is removable pipe
installed in the well through which well fluids pass).
 Provides a means of pressure sealing and isolation between casing
at surface when many casing strings are used.
 Provides pressure monitoring and pumping access
to annuli between the different casing/tubing strings.
 Provides a means of attaching a blowout preventer during drilling.
 Provides a means of attaching a Christmas tree for production
operations.
 Provides a reliable means of well access.
 Provides a means of attaching a well pump.

28. 2.2 Christmas tree
Surface valves manifold to control flow of well fluids & access for well intervention
activities. It is considered as a safety barrier. In petroleum and natural gas extraction,
a Christmas tree, or "tree", is an assembly of valves, casing spools, and fittings used to
regulate the flow of pipes in an oil well, gas well, water injection well, water disposal well,
gas injection well, condensate well and other types of wells.
Features:
1 LMV
Manual, NOT working valve, optimum conditions,
back-up for UMV.
2 UMV
(Hyd/Pneu) emergency valve, “Fail-safe closed”
& cut wire.
3 FWV
Hydraulic, “Fail-safe closed” ,Permits passage of
well
fluids to CV.
4 Chock Valve (CV)
Restrict, control or regulate flow of well fluids.
5 KWV
Permits entry of kill fluids into tubing or equalize.
6 Swab Valve/Crown Valve
Manual, Permits entry of well interventions equip.

29. 2.3 Tubing Hanger
 This component sits in the upper portion of the wellhead,
within the tubing head flange and serves as the main
support for the production tubing.
 The tubing hanger may be manufactured with rubber or
polymer sealing rings to isolate the tubing from the
annulus.
 The tubing hanger is secured within the tubing head flange
with lag bolts. These lag bolts apply a downward pressure
on the tubing hanger to compress the sealing gaskets and
to prevent the tubing from being hydrostatically or
mechanically ejected from the annulus

30. 2.4 Production Tubing
 Production tubing is the main conduit for transporting
hydrocarbons from the reservoir to surface (or
injection material the other way). It runs from the
tubing hanger at the top of the wellhead down to a
point generally just above the top of the production
zone.
 Production tubing is available in various diameters,
typically ranging from 2 inches to 4.5 inches.
 Production tubing may be manufactured using various
grades of alloys to achieve specific hardness, corrosion
resistance or tensile strength requirements.
 Tubing may be internally coated with various rubber or
plastic coatings to enhance corrosion and/or erosion
resistance.

31. 2.5 Downhole Safety Valve (DHSV)
 This component is intended as a last-resort method of protecting the
surface from the uncontrolled release of hydrocarbons. It is a
cylindrical valve with either a ball or flapper closing mechanism. It is
installed in the production tubing and is held in the open position by
a high-pressure hydraulic line from surface contained in a 6.35 mm
(1/4") control line that is attached to the DHSV's hydraulic chamber
and terminated at surface to an hydraulic actuator. The high pressure
is needed to overcome the production pressure in the tubing upstream
of the choke on the tree. The valve will operate if the umbilical HP line
is cut or the wellhead/tree is destroyed.
 This valve allows fluids to pass up or be pumped down the production
tubing. When closed the DHSV forms a barrier in the direction of
hydrocarbon flow, but fluids can still be pumped down for well kill
operations. It is placed as far below the surface as is deemed safe
from any possible surface disturbance including cratering caused by
the wipeout of the platform. Where hydrates are likely to form (most
production is at risk of this), the depth of the SCSSV (surface-
controlled, sub-surface safety valve) below the seabed may be as
much as 1 km: this will allow for the geothermal temperature to be high
enough to prevent hydrates from blocking the valve.

32. 2.5 DHSV (SSSV) Objectives:
•Prevent uncontrollable hydrocarbon flow possible cause by surface impact or
explosion.
•Set below crater depth & above CL hydraulic fluid hydrostatic head.
•DHSV is a “Fail-Safe Closed” type, if hydraulic pressure to the valve is lost, it will
immediately close.
•These valves can also be pumped through from the surface even when they are closed.

33. 2.5 DHSV (SSSV)
• The DHSV is not regarded as a well control barrier. This is because the API permits
a certain amount of leakage through the DHSV: 0.4 l/min liquid.
TRSV
WRSV
1. PASSV
(Pressure Activated Subsurface Control Safety Valve)
-Ambient Pressure
-Differential Pressure
2. SCSSSV
(Surface Control Subsurface Safety Valve)
- WRSV
- TRSV
All Works by Pressure
Two Closure mechanism
-Ball Type - Flapper Type

34. 2.6 Annular Safety Valve
 On wells with gas lift capability, many operators consider it
prudent to install a valve, which will isolate the A annulus
for the same reasons a DHSV may be needed to isolate
the production tubing in order to prevent the inventory of
natural gas downhole from becoming a hazard as it became
on Piper Alpha.
 Some countries require annulus safety valves to be installed in
gas-lift wells on fixed installations.
 The idea is the same as for DHSVs, i.e. to prevent an uncontrolled
reverse backflow of gas from the annulus, if any of the wellhead
and/or Xmas tree equipment should be damaged.

35. 2.6 Annular Safety Valve

36. 2.7 Circulating Devices:
a- Side Pocket Mandrel (SPM)
 This is a welded/machined product which contains a
"side pocket" alongside the main tubular conduit. The
side pocket, typically 1" or 1½'' diameter is designed to
contain gas lift valve, which allows flow of High
pressure gas into the tubing there by reducing the
tubing pressure and allowing the hydrocarbons to
move upwards.
 Provide communication between tubing & annulus.
 Incorporate orienting sleeve, discriminator, receptacle
with profile & seal bores for 1” or 1½'' valves.

37. 2.7 Circulating Devices:
b- Sliding Side Door (SSD)
 A sliding sleeve is a standard component for the
completion of an oil or gas well. Their main uses are to
shut off flow from one or more reservoir zones or to
regulate pressure between zones.
 The sliding sleeve is hydraulically or mechanically
actuated to allow communication between the tubing
and the 'A' annulus. They are often used in multiple
reservoir wells to regulate flow to and from the zones.
 Provide communication between tubing & annulus.
 Incorporate nipple profile. inner sleeve with packing, &
seal bores.

38. 2.8 Anchoring Devices:
Landing Nipples
1- Ported Nipple
2- Top No-Go
3- Bottom No-Go.
4- SV Nipple
 A completion component fabricated as a short section of
heavy wall tubular with a machined internal surface that
provides a seal area and a locking profile. Landing nipples
are included in most completions at predetermined
intervals to enable the installation of flow-control devices,
such as plugs and chokes. Three basic types of landing
nipple are commonly used: no-go nipples, selective-
landing nipples and ported or safety-valve nipples.

39. 2.9 Formation Isolation Devices:
Production Packer
 The packer isolates the annulus between the tubing and the
inner casing and the foot of the well. This is to stop reservoir
fluids from flowing up the full length of the casing and damaging
it. It is generally placed close to the foot of the tubing, shortly
above the production zone.
 Designed to provide seal between casing & tubing. It allows
reservoir fluid to be contained within the tubing up to surface
facility. This isolates production casing from being exposed to
reservoir pressure & corrosion from well effluents or injection
fluids

40. 2. 10 Anti Erosion Devices:
a- Blast Joint
 Designed to protect the tubing’s area, that must remain
opposite the upper perforations exposed to abrasive,
corrosive & sand-laden fluids ( areas of turbulence flow).
 Is a section of pipe that is externally coated with rubber,
tungsten carbide, ceramics or it self a special alloy (SS)
with heavy-walled, (30-20) ft long.
 Installed opposite perforations (non-gravel pack) where
abrasive action & external cutting occurs caused by formation
fluids or sand.
 High velocity & high pressures wells installed both

41. 2. 10 Anti Erosion Devices:
B- Flow Coupling
 This is a thick-walled pipe section that is placed in areas of
turbulent flow; they are simply a thicker section of straight
pipe with proper thread connection with full ID.
 Designed to withstand internal abrasive action
from turbulence formation fluids especially above and
below the landing nipple.. Hence flow couplings of
hardened or special alloy steel usually from (1-10) ft long
are run along the turbulent flow area to prevent tubing
failure.
 Installed opposite perforations (non-gravel completion).

42. 2. 11 Others:
a- Wireline Entry Guide
 This component is often installed at the end of the tubing, or
"the shoe". It is intended to make pulling out wireline tools
easier by offering a guiding surface for the toolstring to re-enter
the tubing without getting caught on the side of the shoe.
 Bottom most tubing accessories.
 Provide easy access for WL tools into tubing.

43. 2. 11 Others:
b- Perforated Joint
 This is a length of tubing with holes punched into it. If used, it
will normally be positioned below the packer and will offer an
alternative entry path for reservoir fluids into the tubing in case
the shoe becomes blocked, for example, by a
stuck perforation gun. (installed above the gauge hanger
landing nipple.
 Eliminate flow restrictions.
 Provide true downhole flow readings, (Temp, Press & flow
readings).
 Prevent vibration of gauges installed in high velocities flowing
production tubing.

44. 2. 11 Others:
c- Control line
Transport hydraulic fluid to SCSSV
Continuous length & securely clamped on tubing wall.

45. 3- Perforating & stimulating
 In cased hole completions (the majority of wells), once the completion string is in
place, the final stage is to make a connection between the wellbore and the
formation. This is done by running perforation guns to blast holes in the casing or
liner to make a connection. Modern perforations are made using shaped
explosive charges, similar to the armor-penetrating charge used on antitank
rockets (bazookas).
 Sometimes once the well is fully completed, further stimulation is necessary to
achieve the planned productivity. There are a number of stimulation techniques.
1- Acidizing:
 This involves the injection of chemicals to eat away at any skin damage, "cleaning
up" the formation, thereby improving the flow of reservoir fluids. A strong acid
(usually hydrochloric acid) is used to dissolve rock formations, but this acid does
not react with the Hydrocarbons. As a result, the Hydrocarbons are more
accessible. Acid can also be used to clean the wellbore of some scales that form
from mineral laden produced water.

46. 3- Perforating & stimulating
3- Fracturing:
 This means creating and extending fractures from the perforation tunnels deeper
into the formation, increasing the surface area for formation fluids to flow into
the well, as well as extending past any possible damage near the wellbore. This
may be done by injecting fluids at high pressure (hydraulic fracturing), injecting
fluids laced with round granular material (proppant fracturing), or using
explosives to generate a high pressure and high speed gas flow (TNT or PETN up
to 1,900,000 psi (13,000,000 kPa) ) and (propellant stimulation up to 4,000 psi
(28,000 kPa).
4- Acid Frac:
 This involves use of explosives and injection of chemicals to increase acid-rock
contact.
5- Nitrogen Circulation:
 Sometimes, productivity may be hampered due to the residue of completion
fluids, heavy brines, in the wellbore. This is particularly a problem in gas wells. In
these cases, coiled tubing may be used to pump nitrogen at high pressure into
the bottom of the borehole to circulate out the brine.

47. COMPLETION DESIGN EXAMPLE-1

48. COMPLETION DESIGN EXAMPLE-2

49. DHSV

52. Well COMPLETION
1 DHSV
 HP of control line fluid
 Earth crater depth
2 Landing Nipple
 Below kick off point for deviation.
 Check well integrity
 Hanging depth for FCD.
3 SPM
 Hydrostatic head of hydrocarbon & communication
4 SSD
 Depth of required communication
5 Packer
 Determined by reservoir depths.
6 Anti-Erosion Device
 Determined by reservoirs & flow characteristics
COMPLETION ACCESSORY DEPTH RATIONALIZATION
1
2
2
2
3
4
5
5
6
6
4

53. WELLHEAD
&
XMAS TREE
Objective:
Provide general knowledge of types,
functional requirements & accessories.

55. Type of Casing
1. Conductor Pipe
2. Surface Casing
3. Intermediate Casing
4. Production Casing
5. Liner
1 CONDUCTOR PIPE
 Prevents unconsolidated formations being
eroded.
 Provides flow path for drilling fluids.
 Cemented in pre-drilled hole or pile driven.
 Sizes ranging from 16" – 30“ OD.
 Depth varies from surface to 40´ - 400´

56. Surface Casing
 Protection in case of blowout & Acts as
wellhead foundation.
 Isolates shallow consolidated & fresh
water formations.
 Cemented along its whole length.
 Sizes ranging from 13 ⅜" - 20“ OD.
 Setting depth up to 1,500´ below surface.

57. Intermediate Casing
 Seals off problem zones, loss circulation
zones, high pressure gas pockets & soft
formations encountered.
 Protects production casing from
corrosive fluids.
 Cemented up to surface casing shoe.
 Sizes ranging from 7" - 13 ⅜" OD.
 Depth depends on total well depth &
conditions encountered, shallow wells
not necessary to set this.

58. Production Casing
 Set above or through producing
formations.
 Isolates reservoir from other fluid
bearing formations.
 Cemented from intermediate casing
shoe to its bottom.
 Sizes ranging from 5" – 9⅝´´ OD.

59. Liner
 Shortened casing hangs from bottom
of previous casing through
producing formations.
 Used when geological & pressure
conditions make it hazardous to
penetrate the producing formation
without the hole being protected by
casing.
 Cemented along its length.
 Cost effective