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Eng. El Sayed Amer
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Email:Eng20072007@gmail.com
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Excellent petroleum Eng.AtSUCO&RWEDEA
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Eng. Elsayed Amer
Petroleum Engineer
Worked for weatherford drillinginternational
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01 Drilling Engineer to Petroleum
Engineer Handover
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A
S
B
P
P
F orm a tion1 0 ,0 0 0 ft
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01
01
Well Completion
The methodology and technology required to produce recoverable
reserves (reservoir to surface).
Process:
The design, selection and installation of tubular, tools and equipment,
located in the wellbore, for the purpose of conveying, pumping or
controlling production (or injection) fluids.
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9
Formation
Annulus
Packer
Surface
Pay ZoneFormation
Surface
Pay Zone
Tubing
A
B
P
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Single Zone / Single String
Tubing
Packer
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Completion design criteria
Wellbore/Reservoir/Interface Producing Zones
A. Open Hole/Barefoot
B. Cased Hole
C. Horizontal
D. Multilateral
A. Single Zone
B. Multiple Zone
A. I. Single String
B. J. Multiple Strings
A. Natural Flow
B. Artificially Induced
01 03
02 04
Production Method Number of Tubing Strings
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Completion cost
££
£
£
€€
€€
Completion fluid
additives,
completion liner and
tubing
wellhead equipment
completion and
perforating crews
13completion
pumping equipment
rentals
completion costs generally fall in the
range of $2.9 MM to $5.6 MM per well
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01 WELL CLEAN UP PROCEDURES
A bit and scraper assembly will be run.
• The purpose of this trip is to clean
out any excess cement within the
casing, and particularly to remove
any cement that may be on the
casing wall at the packer setting
depth.
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01 OIL BASED MUD DISPLACEMENT
Completion Fluid
A completion fluid is defined as any fluid used in a well during downhole operations after the
well has been drilled and cased.
They differ from normal drilling muds in that they are designed to minimize formation
damage to the production zone but at the same time maintain circulating capacity and well
control.
Properties
The design of a successful completion fluid needs to address the following parameters.
• Sufficient density to control downhole pressures;
• Minimize formation damage both chemical and mechanical; .
• Minimize corrosion rates;
• Maximize removal of particulate matter to the surface; .
• Stability with temperature and time;
• Environmental and operational safety;
• Cost effectiveness in overcoming the damage which conventional fluids would cause.
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Completion fluid displacement
The quality of the fluid used during a completion
and workover operation cannot be over
emphasized as the productivity is governed not
only by the damage caused by visible
contaminants such as solids but also the damage
caused by invisible contaminants such as calcium
ions, sulphate ions and dissolved iron.
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Pip tag
A radioactive tag in a sub is installed in the string within the
proximity of the packer.
This sub is used as a marker when performing the GR/CCL.
If the formation has little GR character, radioactive collars
can also be included in the casing string for definitive depth
control.
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Bullet Perforation
• Bullets lose velocity when gun clearance >0.5 in.
• Often use in a unconsolidated formations
• Cheaper to use, rarely been used today
• Bullets plug the end of the flow channel
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02 Landing Nipples ( X or XN No-Go Landing Nipple )
Applications
• special tubular made up as part of the production string incorporating a machined
profile into which specific locking devices can be set.
X Setting Nipples
XN No-go nipples
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02 Landing Nipples ( X or XN No-Go Landing Nipple )
Nipples are installed at various points in the string to facilitate one or more of
the following operations:
1. Plugging the tubing for:
(I) pressure testing
(ii) setting hydraulic set packers
(iii) zonal isolation
2. Installing flow control equipment such as:
(I) Downhole chokes, regulators, SSVs, etc.
(ii) landing off bottom hole pressure recorders.
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02 Landing Nipples
( X or XN No-Go Landing Nipple )
No-Go Restriction
Locking Profile
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03 Perforated Joint
Applications
• A Perforated Joint incorporated in the completion
string for the purpose of providing bypass flow if
bottomhole pressure and temperature gauges are
used for reservoir monitoring
• The design criteria for a Perforated Joint is that the
total cross-sectional area of the holes should be at
least equivalent to the cross sectional area
corresponding to internal diameter of the tubing.
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04 Production packer
Applications
• A Packer is a sub-surface tool used to provide a seal between
the Tubing and Casing (or wall) of a well , thus preventing the
movement of fluids past this sealing point.
CN06136
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04 Production packer
1
4
2
3
5
6
To protect the casing from corrosive fluids / gasses
To keep-off high formation pressures off the casing and
wellhead
Pressure testing of the Casing
Detection of a casing leak
To shut-off gas or water entry
During fracturing, to keep high pressures off the casing
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(Slip) assembly
Packing elements
mandrel
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04 Production packer
Sealing or
packing
element
Slips
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04 Production packer
Hydraulic Set
1. Packer set using internal pressure (against
tubing plug).
2. Pressure acts through port on setting
sleeve.
3. Shear pin breaks
4. Setting sleeve drives bottom slips up
against cone .
5. Element and upper slips energized then
slips break and bite into casing
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04 Production packer
PKR setting mechanism
1 Mechanically
2
Hydraulic
• Rotation - Compression - Tension
• Pressure applied to tubing or annulus.
• Differential pressure acts on setting tool (permanent packer) or internal
setting sleeve (retrievable packer).
• Preferred method for deep / deviated wells
3 Electrical
• Mechanical setting mechanism using wireline setting tool
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08 Side Pocket Mandrel
applications
• Gas, at a controlled volume and pressure, is injected
into the tubing/casing annulus.
• The tubing string has been fitted with a number of gas
lift valves.
• These valves are installed at spaced intervals so that any
liquid present above them in the casing/tubing annulus
can be removed by injection of gas at the top of the well
annulus leading to the liquid U-tubing into the tubing
and its subsequent ejection from the well.
Gas Lift System
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09 Subsurface Safety Valves
applications
• are fail-safe valves that are designed to prevent an
uncontrolled release of hydrocarbons from the well if
something catastrophic occurs at surface.
Application
Two basic types of safety valves:
• Tubing conveyed: Tubing Retrievable Subsurface Safety
Valve (TRSV),
• Wireline conveyed: Wireline Retrievable Subsurface
Safety Valve (WRSV
Types
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09 Subsurface Safety Valves
applications
• A downhole safety valve that is operated from surface
facilities through a control line strapped to the
external surface of the production tubing.
• The control system operates in a fail-safe mode, with
hydraulic control pressure used to hold open a ball or
flapper assembly that will close if the control pressure
is lost.
surface-controlled subsurface
safety valve SCSSSV
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Why a Sub-Surface Safety Valve (SSSV)?
applications
• Catastrophic platform accident
due to explosion in process
facility and release of gas in
pipeline
• Almost all of the wells controlled
below seabed with SC-SSSVs!
• Only well that burnt was being
worked over – no SSSV in place
Piper Alpha tragedy
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10 Tubing
applications
• Production tubing is installed to allow hydrocarbons to
flow from reservoir to the surface and protect the casing
from reservoir fluid.
• production tubing generally averages 28-32 feet in
length.
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10 Tubing
applications
Tubing is “typed” according to four criteria.
I. Size :
Refers to the outside diameter (in inches or millimeters) or the tube body itself.
Tubing is available in various external diameters. API recognized sizes for production
tubing vary from 3/4 inch to 4 1/2 inch.
II. Weight:
An average given in pounds/foot of kilograms/meter. Tubing is available in various
weights for each particular size.
III. Grade:
Term used to describe the type of metal alloy of which the pipe is made. J-55, N-80, P-
105.
IV. Thread:
Design of the connection on either end of the pipe
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10 Tubing
applications
Tubing is “typed” according to four criteria.
I. Size:
is the outside diameter of the pipe body. The most used sizes
are:
2-⅜” , 2-⅞” , 3-½” and 4-½”.
Tubing Size Capability
Outside Diameter Wall Thickness Range
Inches Mm Inches Mm
2-3/8 60.33 .190 -.336 4.83 - 8.53
2-7/8 73.03 .217 -.308 5.51 - 7.82
3-1/2 88.9 .289 - .375 7.34 - 9.53
4 101.6 .226 -.330 5.74 - 8.38
4-1/2 114.30 .271 - .337 6.88 - 8.56
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10 Tubing
applications
Tubing is “typed” according to four criteria.
I. Size:
is the outside diameter of the pipe body. The most used sizes
are:
2-⅜” , 2-⅞” , 3-½” and 4-½”.
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10 Tubing
applications
Tubing is “typed” according to four criteria.
II. Length:
Tubulars are manufactured in lengths termed joints
range 1 : 20 to 24 feet;
range 2 : 28 to 32 feet;
range 3 : 32 to 48 feet
Pup joints or spacers are used for shorter lengths.
Tubing Ranges
Range 1 (feet) Range 2 (feet) Range 3 (feet)
20-24 28-32 38-42
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PUP JOINTS
Pup joints are short tubing joints that give flexibility in attaining
a desired tubing length
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10 Tubing
applications
Tubing is “typed” according to four criteria.
III. Grade:
Tubing grades criteria are specified by API:
• Standard API grades J-55, C-75, C-95, N-80, P-105
• Special grades e.g., C-75 and C-95 for H2S
service
Selection of tubing grade is based on:
• Physical strength
• Chemical Properties (resistance to H2S, CO2, water
etc.)
• Availability and standardization at customer
• Cost
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10 Tubing
applications
Tubing is “typed” according to four criteria.
III. Grade:
• Sour Corrosion: resistance to H2S, low hardness, stress relieved,
J55, C75, C95.
• Sweet Corrosion: CO2, provisions for inhibition or appropriate
material selection, L80 13 Cr
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10 Tubing
applications
Tubing is “typed” according to four criteria.
III. Connections:
Two standard API Connections available:
1. Non-Upset (NUE):
• is a 10 round thread.
• Joint strength<Pipe body
2. Upset Connection (EUE)
• Is a 8 round thread.
• Joint strength>pipe body
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Non-upset
(8 round) Connection
External Upset
Connection
EUE
Integral Connection
Hydril
Integral Connection
Production Tubing connections
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Production
Tubing
Design of production tubing should satisfy the following criteria:
• Minimizing pressure drop
01
02
03
04
• High strength for suspension
of tubing joints
• High internal pressures for
fluids flow
• High external pressures
(between annulus & tubing)
05 • Resistant to chemical
corrosion
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Tubing Connection Make up Torque
I. Under torque ------------------ leakage
II.Over torque ------------------thread failure &
damage to seal
I. Recommended torque values are applied by manufactures .
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11 Tubing Hanger
applications
• A device attached to the topmost
tubing joint in the wellhead to
support the tubing string. The
tubing hanger typically is located
in the tubing head, with both
components incorporating a
sealing system to ensure that the
tubing conduit and annulus are
hydraulically isolated
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Tubing Hanger
• The tubing hanger's function is to transfer the weight of the tubing to the wellhead and to
contain the casing - tubing annulus fluid
• Set in THS , suspend tubing weight & provide sealing
• The main problem with hanger selection occurs where the tubing is to be landed in tension
(e.g. in some gas wells and rod pumping wells), when this is applied mechanically rather
than hydraulically.
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• three main methods of setting, manipulating, and retrieving
down hole tools:
F i r s t
Mechanically
Tubing
Drill Pipes
Coiled tubing
S e c o n d
Hydraulically
Surface Pipe
Pressure
Well Hydrostatic
Pressure
T h i r d
Wireline
Electrical Line
Braided line
Slick line
ToolSettingandRetrievalMethods
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TWB
PERMA-SERIES®
PACKER
HYDRAULIC CONTROL LINE
SIDE POCKET
MANDREL
LANDING NIPPLE w/X NIPPLE PROFILE
FLOW COUPLING
FLOW COUPLING
SIDE POCKET
MANDREL
SIDE POCKET
MANDREL
LINER
HANGER
RH HYDRAULIC-SET
PACKER
CIRCULATING DEVICE
w/X NIPPLE PROFILE
BLAST JOINT
NO-GO NIPPLE
w/XN NIPPLE PROFILE
SLIDING SIDE-DOOR®
CIRCULATING DEVICE w/X NIPPLE PROFILE
Single Selective
Completion
System
SURFACE-CONTROLLED
TUBING-RETRIEVABLE
SAFETY VALVE w/X NIPPLE PROFILE
