The document discusses well completion processes. It describes the different types of well casing installed during completion, including conductor, surface, intermediate, production, and liner casing. It also discusses functions of casing like strengthening the wellbore and preventing fluid migration. The document outlines various completion methods like open hole, cemented liners, gravel packs, and describes how zones are produced. It classifies completions based on reservoir interface, production method (natural flow, artificial lift like rod pumps and ESPs), and number of zones. The artificial lift methods support production when natural reservoir pressure declines.

1. THE WELL
• When the well has been drilled, it must be
completed, completing a well consists of a
number of steps, such as installing the well
casing, completion, installing the wellhead,
and installing lifting equipment or treating the
formation should that be required.

2. THE WELL CASING
• Installing the well casing is an important part
of the drilling and completion process. Well
casing consists of a series of metal tubes
installed in the freshly drilled hole.

3. FUNCTION OF CASING
• Casing serves to strengthen the sides of the
well hole.
• Ensure that no oil or natural gas seeps out as
it is brought to the surface.
• And to keep other fluids or gases from seeping
into the formation through the well.

4. • A good deal of planning is necessary to ensure
that the right casing for each well is installed.
Types of casing used depend on the
subsurface characteristics of the well,
including the diameter of the well (which is
dependent on the size of the drill bit used.)
and the pressures and temperatures
experienced.

5. • In most wells, the diameter of the well hole
decreases the deeper it is drilled, leading to a
type of conical shape that must be taken into
account when installing casing. The casing is
normally cemented in place.

6. There are five different types of well
casing. They include:
1. Conductor casing
2. Surface casing
3. Intermediate casing
4. Production casing
5. Liner strings

7. Conductor casing
which is usually no more than 20 to 50 feet (7-
17 meter) long, installed before main drilling to
prevent the top of the well from caving in and to
help in the process of circulating the drill fluid
up from the bottom of the well.

8. Surface casing
• Surface casing is the next type of casing to be
installed. It can be anywhere from 100 to 4500
meters long, and is smaller in diameter to fit
inside the conductor casing.

9. • Its primary purpose is to protect fresh water
deposit near the surface of the well from
being contaminated by leaking hydrocarbons
or salt water from deeper ground. It also
serves as a conduit for drilling mud returning
to the surface and helps protect the drill hole
from being damaged during drilling.

10. Intermediate casing
• Intermediate casing is usually the longest
section of casing found in a well. Its primary
purpose is to minimize the hazards associated
with subsurface formations that may affect
the well.

11. • These include abnormal underground
pressure zones, underground shales and
formations that might otherwise contaminate
the well, such as underground salt water
deposits.

12. • Liner strings are sometimes used instead of
intermediate casing. Liner strings are usually
just attached to the previous casing with
‘hangers’, instead of being cemented into
place and thus less permanent.

13. Production casing,
Production casing, alternatively called the ‘oil
string’ is installed last and is the deepest section
of the casing in a well. This is the casing that
provides a conduit from the surface of the well
to the petroleum producing formation.

14. • The size of the production casing depends on
a number of considerations, including the
lifting equipment to be used, the number of
completions required, and the possibility of
deepening the well at a later date.

15. • For example, if it is expected that the well will
be deepened later, then the production casing
must be wide enough to allow the passage of
a drill bit later on. It is also instrumental in
preventing blow outs, allowing the formation
to be sealed from the top should dangerous
pressure levels be reached.

16. • FIG 1.1 Casing Schematics (Source Schlumberger)

17. WELL COMPLETIONS
• Well completion can be referred as the
activities and methods necessary to prepare a
well for the production of oil and gas or the
process of finishing a well so that it is ready to
produce oil or natural gas.

18. • The term completion is plagiarized from the
operation to complete a well for production
after it has been successfully drilled.
Dependent upon the reason for which the
well was drilled (i.e.)

19. • Wildcat/exploration well: A well drilled in an
area where no oil or gas production occurs.
• Appraisal well: A well drilled to further
confirm and evaluate the presence of
hydrocarbons in a reservoir that has been
found by a wildcat well.

20. • Production: A development well specifically
for the extraction of reservoir fluids. and the
results of logging and /or well test results, the
well will then be:
• Abandoned( as it has no further use i.e. a
duster)
• Plugged (Suspended as a future or possible
production well).
• Completed as a production well.

21. WELL COMPLETION OPERATIONS
INCLUDE:
• Perforation
• Sand control
• Production packer installation
• Tubing (completion) string/tubing hanger
installation.
• Downhole safety valve installation
• Xmas tree installation.
• Bring the well onto production

22. CLASSIFICATION OF COMPLETIONS
Completions may be classified with respect to
the following:
• Reservoir / wellbore interface
• Mode of production
• Number of zones completed

23. Reservoir / wellbore interface
1. Open hole completion
2. Uncemented liner completion
• External graval pack
• Pre packed screen
• Wire wrapped screen
• Slotted pipe

24. 3. Perforated liner completion
4. Perforated casing completion.
• Internal gravel pack
• standard

25. Mode of production
1. Flowing naturally
• Tubing or Tubingless
2. Artificial lift
• Electric submersible pump
• Plunger lift
• Gas lift
• Hydraulic pump
• Rod pump

26. Number of zones completed
1. Single
• Interval co-mingling
• standard
2. Multiple
• Interval segregation
• Concentric string
• Multiple strings
• Twin string ,dual completion
• Single string , dual completion

27. CLASSIFICATION BY
RESERVOIR/WELLBORE INTERFACE
• Open hole completion are the most
uncomplicated type and are only used in very
competent formations, which are unlikely to
cave in. An open hole completion consists of
simply running the casing directly down into
the formation, leaving the end of the piping
open without any other protective filter. This
method is used where it is required to expose
all zones to the wellbore.

28. • Figure 1.3 Open hole completion schematic (Aberdeen
drilling school, 2002)

29. Advantages of Open Hole Completions
are:
• The entire pay zone is open to the wellbore.
• Perforating cost is eliminated.
• Log interpretation is not critical since the
entire interval is open to flow
• The well can easily be deepened
• Is easily converted to liner or perforated
casing completion
• Minimal formation damage is caused by
cement.

30. Disadvantages of Open Hole
Completions are:
• The formation may be damaged during the
drilling process.
• Excessive gas or water production is difficult
to control because the entire interval is open
to flow.
• The casing may need to be set before the pay
zone(s) are drilled and logged.

31. • Separate zones within the completion cannot
be selectively fractured or acidized.
• Requires frequent clean out if producing
formations are not consolidated.
• May be difficult to kill if installed in a
horizontal well for well servicing or workover
or abandoned purposes.

32. Uncemented liner completion
• In some formations hydrocarbons exist in
regions where the rock particles are not
bonded together and sand will move towards
the wellbore as well fluids are produced; this
formation is usually referred as an
unconsolidated formation.

33. • The use of uncemented liners (slotted or
screened) acts as a strainer stopping the flow
of sand. Liners are hung off from the foot of
the production casing and usually sealed off
within it to direct any well flow through the
liner bore.

34. Advantages of uncemented liner
completions are:
• Entire pay zone open to the wellbore.
• No perforating cost
• Log interpretation is not critical.
• Adaptable to special sand control methods.
• No clean out problems.
• Wire wrapped screen can be placed later.

35. Disadvantages of uncemented liner
completions are:
• The formation maybe damaged during the
drilling process.
• Excessive water or gas is difficult to control.
• Casing is set before pay zones are drilled and
logged.
• Selective stimulation is not possible

36. Uncemented liner completions are not used
very often since:
• Sand movement into the wellbore causes
permeability ( flow rate ) impairment
• Screen erosion can occur at high production
rates.

37. • These problems may be overcome by filling
the annulus between the open hole and
screen with graded coarse sand, I.e. gravel
packing, which acts to support the open hole
section as well as prevent formation sand
movement.

38. Perforated cemented liner completion
In perforated cemented liner completions, the
casing is set above the producing zone and the
pay section drilled. Liner casing is then
cemented in place which is subsequently
punctured (perforated) by bullet–shaped
explosive charges.

39. • These perforations are designed to penetrate
any impaired regions around the original
wellbore to provide an unobstructed channel
to the undamaged formation.

40. • By using various depth measuring devices (i.e.
casing collar locator, CCL) various sections of
pay zone can be perforated accurately(
excluding unproductive regions), avoiding the
production of undesirable fluids( gas or
water), or production from unconsolidated
sections that might produce sand.

41. • The various methods of completing well using
perforated cemented liner operations are:
• Single
• or multiple pay zone

42. Figure 1.8 Perforated cemented liner schematic
(Aberdeen drilling school, 2002)

43. Perforated cemented casing
completion
• In a perforated cement casing completion, the
hole is drilled through the formation(s) of
interest and production casing is run and
cemented across the section.

44. • Again, this requires that perforations be made
through the casing and cement to reach the
zone(s) of interest and allow well fluids to flow
into the wellbore.
• Methods of completing a well in perforated
cemented casing completions are

45. A. Standard perforated cemented casing
Figure 1.9 standard perforated cemented casing
schematic (Aberdeen drilling school, 2002)

46. B. Internal gravel packs
• This is where the production casing is
cemented. Perforation of the producing
interval(s) is then performed and the
perforations cleaned out. A screen is run and
gravel is pumped into the casing/screen
annulus and perforation tunnels

47. Figure 1.10 internal gravel pack perforated cemented
casing schematic (Aberdeen drilling school, 2002)

48. Classification-by Mode of production
• When the hydrocarbon reservoir can sustain
flow due to its natural pressure, flow may be
up the production casing string, up the tubing
strings, or both.

49. Tubingless completions
• Casing flow completions are a particular low-
cost method in marginal flow conditions such
as low rate gas wells. Casing flow completions
are discouraged because the production
casing is exposed to well pressure and /
corrosive fluids. And there is also an increased
risk of collision damage offshore and there is
no facility to install downhole safety valves.

50. • Figure 1.11 tubingless schematic (Aberdeen
drilling school, 2002)

51. Tubing Flow Completion
• Tubing flow completion utilise the tubing to
convey well fluids to surface. Flow rate
potential is much lower in tubing flow than in
unrestricted casing flow completions. As well
as for production, the tubing string can be
utilised as a kill string or for the injection of
chemicals.

52. • Tubing strings may also accommodate gas lift
valves which essentially gas assist well liquids
to surface; these valves would be installed if
formation pressure diminished considerately
and natural drive ceased.

53. • By far the most common methods of
completing a well is to use a single tubing
string/packer system where the packer is
installed in the production casing to offer
casing protection, subsurface well control, and
an anchor for the tubing.
Examples of such completions methods are:

54. Simple low cost
Figure 1.12 temporary tubing schematic (Aberdeen
drilling school, 2002)

55. Other equipment commonly installed in the
tubing string to facilitate a safer production
system are:
Wireline nipples: Permits the installation of flow
controls or plug.
Tubing retrievable safety valve: For emergency
well shut-in

56. • Safety valve landing nipple : Permits the
installation of a surface control subsurface
safety valve(SCSSV) for emergency shut-in.
• flow couplings : Fitted above the packer for
circulating purpose.
• Tubing seal device : To allow tubing
Movement.

57. • Packers : Designed to isolate production zones
and isolate the casing annulus from well
pressure.
• Circulation devices: Also known as Sliding
Sleeves Door; these allow communication
between the tubing and annulus.

58. • Side pocket Mandrels : SPM’s are positioned
in a completion to provide a point of injection
of lift gas, chemical inhibitor or kill valves.
• Blast Joints : BJ’s are external hardened, heavy
walled sections of tubing that are spaced out
across the perforations of the upper zones to
protect the tubing from abrasive wear.

59. Surface Controlled Subsurface Safety Valves
:Designed and Installed on all offshore wells and
land wells. they are designed to shut in the well
in an emergency.
Telescoping travel joint: TTJ’s are installed in
dual completions to assist spacing out the
second string, and allow for thermal expansion
in the tubing.

60. Artificial lift
• When a reservoir’s natural pressure is
insufficient to deliver liquids to surface
production facilities, artificial lift methods are
necessary to enhance recovery. Various
artificial lift completions method are discussed
below

61. Artificial lift methods
• Rod pump lift
• Gas lift
• Hydraulic pump lift
• PLUNGER LIFT
• Electric Submersible pump(ESP)

62. Rod pump lift
• These pumps consist of a cylinder and piston
with an intake and discharge valve. Vertical
reciprocation of the rod will displace well fluid
into the tubing. These are utilised in low
moderate wells which delivers less than
2000BPD (318m3/day).

63. Figure 1.14 Rod pump lift schematic (Aberdeen
drilling school, 2002)

64. Hydraulic pump lift
• Hydraulic pump lift is utilised in crooked holes,
for heavy oils and variable production
conditions that cause problems for
conventional rod pumping.

65. • Three types of hydraulic pump exist to lift
liquid:
• Piston
• JET
• Turbine

66. Piston
• Consists of a set of coupled pistons, one
driven by a power fluid and the other
pumping the well fluid; systems exist for
production up the annulus or up the tubing.

67. Figure 1.15 Piston pump lift schematic (Aberdeen
drilling school, 2002)

68. JET
• Converts power fluid to a high velocity jet
which pulls the well fluid up into the flow
stream.

69. Turbine
• Power fluid rotates a shaft on which a
centrifugal or axial pump is mounted.

70. Figure 1.16 turbine lift schematic (Aberdeen
drilling school, 2002)

71. PLUNGER LIFT
The plunger lift system is a low rate lift system in
which annulus gas energy is used to drive a
plunger carrying a small slug of liquid up the
tubing when the well is opened at surface.
Subsequent closing of the well allows the
plunger to fall back to bottom.

72. • Figure 1.17 Plunger lift schematic (Aberdeen
drilling school, 2002)

73. Electric Submersible pump(ESP)
• An ESP is used for moving large liquid volumes
of low gas /liquid ratio from reservoirs with
temperatures below 250◦f, e.g. water wells,
high water cut producers and high
deliverability under saturated oil well.

74. • Figure 1.18 ESP schematic (Aberdeen drilling
school, 2002)