Completion string
What is a completion string?
The completion string consists of tubing and other equipment
necessary to achieve optimal flow performance and safety during
production of hydrocarbons to the surface orinjection of fluids to
the formation. If there is a surface leak, the down hole safety
valve (DHSV) which is a part of the completion string can be closed
and thus prevent hydrocarbon escape at the platform.The completion
string will also protect the casing from the formation pressure and
corrosion attacks by the well fluid.
Components
Common completion string components are:
Tubing hanger
Tubing joints
Completion string connections
Control lines
Down hole instrumentation and control system (DIACS)
Down hole safety valve (DHSV)
Annular safety valve (ASV)
Gas lift valve (GLV)
Side pocket mandrel (SPM)
Permanent down hole gauge (PDG)
Production packer
Electrical submersible pump (ESP)
Sand control equipment
Other completion string components are:
Adjustable union
Blast joint
Casing packer
Circulation valve
Crossover joint
Debris sub
Disappearing plug
External casing packer
Flow coupling
Fluid loss control valve
Indicating coupling
Landing nipple
Orienting swivel joint
O-ring seal sub
PBR seal assembly
Perforated pup joint
Pump-out sub
Pup joint
Safety joint
Seal bore
Tubing anchor
Wireline entry guide
Several components in the completion string are well barrier
elements like the downhole safety valve and the production packer.
Other components have no well barrier function like downhole gauges
and sand control equipment.
What does it look like
The figure below shows a typical completion string with themajor
components and their location.
Figure 1: Typical completion string
Configurations
The most common configuration of the completion string isto have
an 'upper' completion ending with a tail pipe just belowthe
production packer.Another commoncompletion string configuration
includes an upper and lower part where the lower completion often
refers to the sand control equipment installed. Other expressions
used to describe the completion string configuration follow:
Single string
Dual string
Monobore
Straight bore
Tapered bore
Installation
The completion string is installed in the well after all casing
and liners have been run and cemented in place as part of the well
drilling process. The completion string is landed in the wellhead
when using a vertical Xmas tree (topside or subsea).For subsea
completed wells with horizontal Xmas trees the completion string is
landed inside the Xmas tree block. The process of installing the
lower and upper completion string for a selected case is described
below:
Lower completion string installation
Upper completion string installation
Replacement
Most equipment in the completion string is permanently installed
and the completion string must be pulled to replace these items.
This is called a workover or heavy intervention. Some permanent
equipment is repairable or replaceable from inside the string
through wireline or coiled tubing operations. This is called a
thru-tubing intervention or light intervention. There can also be
temporarily installed equipment in the completion string like plugs
and memory gauges.
Operating modes
Operating modes describe the flowdirection and themedium flowing
through the completion string.Major operating modes are:
Gas injection wells
Gas producing wells
Oil producing well
Simultaneous water and gas injection wells (SWAG)
Water alternate gas injection wells (WAG)
Water injection wells
Water producing wells
The operating mode may change during the lifetime of the well.
One example isconversion ofan oil producing well to agas producer.
This can be achieved through minor equipment changes or through a
major workover.Requiredchanges depend on selected equipment and
materials in the initial well.Some oil wells have limited
production performance due to low reservoir pressure.Oneoption for
improvedproduction performance is pressure support throughwater or
gas injection wells. Another option is artificial lift.
Artificial lift
Tubing size and flow rate
The production flowrateis determined by the reservoirpressure,
the density of the completion string fluid and the flow resistance
from the reservoir to the separator. The flow resistance can
further be divided into:
Drawdown from the reservoir to the wellbore
Flow resistance through the completion string
Topside throttling at the choke
First stage separator pressure
The reservoir pressure minus the density of the completion
string fluid is the 'driving force' for the flow. Reduced pressure
in the completion string due to pressure drop may cause free gas
(pressure below the bubble point) which reduces the fluid density
causing increased 'driving force' for well production. This will
also be the effect by injecting gas into the tubing. The optimum
tubing size is selected to provide highest possible flow rate
without tubing failures or other operational problems like slugging
during the operational lifetime. Large tubing will reduce the flow
friction through the completion string and cause higher
drawdown.This will not always cause higher flow rate. The reason is
the reduced inflowperformance from the formation to the near
wellbore and finally into the wellbore.
The flow resistance and flow rateinto the wellbore (inflow
performance) is decided by the inflow performance relationship
(IPR) curves worked out by the reservoir engineers. These curves
are affected by e.g. skin effect, well pressure below the bubble
point, water cut, reduced reservoir pressure with time, etc. The
flow resistance and flow ratethrough the completion string and to
the seperator (outflow performance) is calculated in flow
simulations and presented as outflowperformance relation ship(OPR).
OPR's for different tubing sizes and the IPR curve is presented in
the same plot to determine optimal tubing size.The flow rate is
determined by the intersection point between the IPR and the
OPRcurve (same flow rate). Some times a smaller size tubing is
selected to e.g. provide stabile flow rate. Thus, tubing size
selection is not only decided by flow rate calculations through the
completion string, but by the total flow resistance from the
reservoir to the separator.The completion engineer must discuss the
completion string design with the drilling engineer to solve
potential conflicts with the casing program. The completion
engineer must also calculate the velocities in the completion
string and evaluate if erosion will be a problem.
Grade, weight and materials
The tubing grade (strength), weight (wall thickness) and
materials (corrosion, erosion, etc) is decided in the conceptual
completion design phase, while the equipment procurement will be a
part of the detailed completion design phase. Tubing materials are
decided by the operators material experts. The tubing grade and
weight will be a result from thetubing stress analysis.
Tubing stress analysis
Materials selected for downhole equipment like downhole safety
valve (DHSV) may benobler than the materials used for the tubing
due to additional requirements like sealing performance,wear
resistance,etc.
Synonyms
Synonyms for outflow performance relationship (OPR) are:
Vertical lift performance (VLP) curves
Tubing performance curves (TPC)
Tubing hanger
What is the tubing hanger?
The tubing hanger forms part of the secondary barrier in a well
and is located at top of the completion string. The purposes of the
tubing hanger is to enable to run, hang-offand set (orient and
lock), and seal the completion string either inside the wellhead or
inside the valve block of the horizontal subsea Xmas tree. It forms
the main structural load-bearing and supporting interface for the
completion string. The tubing hanger also accommodates the number
of required down hole control line penetrations and connections,
and thus an important function required for the tubing hanger is
the alignment orientation and sealing interface to the wellhead or
alternatively inside the valve block of the horizontal Xmas
tree.
Types
The following types of tubing hangers are commonly used:
Tubing hangerfor vertical topside Xmas tree
Tubing hanger for vertical subsea Xmas tree
Tubing hangerfor horizontal subsea Xmas tree
There is also available a dual string tubing hanger which allows
for two completion strings to be run down hole, mainly used for
topside wells, but this is not described further here.
Configurations
The required number of downhole control lines to accommodate
will sometimes require special design and qualification
requirements for the tubing hanger, in particular for subsea wells.
The number of lines can vary from one or two and up to ten for some
subsea well completions with DHSVs, several zone control systems
(DIACS) and downhole gauges. These will involve a number of
different stab-in and sealing design solutions for the hydraulic
and electric lines, depending on the tubing hanger type and the
requirements to the control lines themselves.
Tubing joint
What is a tubing joint
A tubing joint is a single tubular pipe and is the basis
component in the completion string. Tubing joints are part of the
primary well barrier above the production packer and below the
DHSV. The major issues to specify for a tubing joint are:
Outside diameter
Weight per foot (instead of ID)
Length
Drift ID
Material, alloy and grade
Connection
Most well tubulars are specified by the outside diameter. Weight
per foot is used instead of specifying the inside diameter.ISO
11960 divides thejoint lengthintothree ranges, where range 1
includes the shortest andrange3 the longest joints. A typical joint
length in range 3 is 12 meters.The drift ID must be known to allow
safe passage of any equipment.Tubing is manufactured and supplied
in various materials, alloys and grades for different operating
conditions, applications and dimensional requirements. Tubing
joints are also delivered with a high number of various threaded
connections available from different manufacturers. One option is
theintegral connection typewith a box (internal threads) and a pin
(external threads)on theendsof the tubing joint. Another option is
thecouplingconnection type with pin (external threads)on both ends
of the tubing joint and a separate connector as a box (internal
threads) in between.
Completion string connections
What are completion string connections
A completion string connection is a threaded connection to
connect completion string components. The connection mustprovide
sufficient pressure-and structural integrity.Both pressure- and
structural integrity are influenced by physical loads in the
completion stringlike tension, compression, bending and torsion.
Major environmental conditions having influence on the pressure-
and structural integrity are pressure differential, temperature and
the surrounding medium. Combinations of physical loads,
environmental conditions, design details, materialsand surface
treatments have influence on the resistance to failure mechanisms
like deformations, galling, corrosion and cracking.
Types
The two main connection types are:
Integral
Coupling
Detailed connection designs are described in API and ISO
standards. Mostvendors offer modified connection designs for
improved performance including higher axial strength, reduced OD
and improved pressure integrity. These modified connections are
often called premium connections. In the North Sea, the premium
connections are used for almost all casing and tubing
applications.
Threads
Common thread types used for completion string connections
are:
API standard 8 round thread
API standard 10 round thread
API buttress thread
Reversed angle load flank thread (also called Hook well
thread)
Premium threads (vendor specific types)
Premium threads are often based on modified versions of the API
buttress thread form or modified versions of the reversed angle
load flank thread. Contact the manufacturers of the premium threads
for more details about their respective thread designs. The API
standard 8- and 10-round threads are now rarely used for any
completion string applications. The basic API buttress thread
however might still be used for downhole tubulars in some cases
around the world.
Seals
Common pressure seal principles are:
Thread seals
Polymer seals
Metal to metal seals
The thread seal is dependent on a thread compound to seal the
clearance between the mating thread elements. The thread compound
may dry out due totemperature, time and exposed medium, reducing
its sealing properties and especially for gases.
The polymer seals typically use a Teflon seal ring in a groove
between the mating surfaces. Teflon rings will expand more than the
metal upon heating. Combined with extrusion, this may cause
deformed seal and thus leakage upon cooling. The seal may be
acceptable at reduced pressure and temperature applications.
The metal to metal seals are shoulder type, sliding type or a
combination. The shoulder type makes axial compression strain and
stresses in the connectionshoulder when the connectionis preloaded.
The sealing force is proportional to the preload. The torque during
make-up is thus of high importance. Too low preload will cause too
low sealing stresses and too high preload will cause yield in the
sealing surface. The sliding type makes radial compression strain
and stresses in the interface between a curved surface at the pin
and a conical surface on the mating part. The sliding type seal may
be pressure energised (increased sealing stresses and thus
sealability when exposed to pressure) or energised by a reverse
angle torque shoulder. Premium connections use metal to metal seals
which are the most reliable seals,especially at high pressure and
temperature.
Vendordesigns
Short introductions to selected premiumconnectionsfrom different
vendors follow:
Hunting
JFE
NKK
TenarisHydril
VAM
Other
More details on the above connections can be foundin the annual
Casing& Tubing Reference Tables published in the November and
January editions of 'World Oil'.
Note that special connections exist for the completion string
and casing when these are parts of a so-called top tensionriser
system. Examples of applied connections for this application are
Grant Prideco (HFR1, HFR1 EE, HFR2), Shell JDS and Mannesmann
PRC.
Control line
What is a control line
Control lines are small diameter metaltubular clamped or banded
to the outside completion string and run down hole with it. The
control lines are used for hydraulic remote operation ofdownhole
equipment such as downhole safety valvesand transferring sensor
signals from down hole gauges for pressure, temperature and flow
monitoring. Hydraulic control lines are simple metal tubulars. Such
tubes can also be used forinjection ofchemicals downhole such as
scale and corrosion inhibitors, but are then often called injection
lines. Typical OD's and wall thicknesses forsingle hydraulic
control linesand chemical injectionlines are:
OD x 0.035" wall thickness
OD x 0.049" wall thickness
OD x 0.065" wall thickness
Increased wall thickness means higher pressure resistance.
Required pressure class is calculated for the tool to be operated.
See e.g. the down hole safety valve (DHSV).The tubesmay be either
seamless- or welded tubes. The seamless tubes are more expensive
andlimited in length compared to the welded tubulars. Common
materials for the control line metal tubular are:
AISI 316L
Incoloy 825
Inconel 625
Each alloy can be studied in the material database. Common
fittings for the hydraulic control lines and chemical injection
lines are:
Swagelok
Autoclave
API 6A recommends Autoclave at pressure classes above 5000
psi.
Types
Different types of control lines are:
Hydraulic control line (tube)
Electric control line (tube/cable insulation/electric
conductor)
Fibre-optical control line
Flat pack umbilical combines one or several lines in an
encapsulated flat configured umbilical with special clamps for
clamping to the completion string. The encapsulation is a
thermoplastic that increases the crush and wear resistance during
installation. The cruch resistance can further be improved by
including one or more braided wires alongside with the control
lines inside the encapsulation.
Downhole instrumentation and control system (DIACS)
What is DIACS
DIACS is the common term used for well completion equipment and
systems that include the functionality to remotely control from the
surface the inflow and monitor the production from several zones or
lateral branches down hole individually without the need for
intervention tools. DIACS is alternatively used to remotely control
and monitor the injection into several injection zones
individually.
The DIACS is installed as an integrated part of the completion
string and consists normally of tubular components with a number of
remotely controlled inflow control valves (ICVs), zonal isolation
packers, downhole gauges for flow-, pressure- and temperature-
monitoring, and one or several downhole control lines. The inflow
valves are mainly sliding sleeve type valves with the following
positions: Full closed, full open or intermediate. The intermediate
position can be stepwise or infinitely variable. Both the
production packer and the zonal isolation packers will have a
design that allows for the control lines to be feed-through without
impairing the sealing function of the packers.
Figure 1: Example of DIACS system for 3 zones with isolation
packers.
Types
Different types of DIACS exist. The type of system is often
classified from what kind of valve actuation that is used for the
ICVs. The following types of DIACS are classified:
Electric DIACS
Hydraulic operated DIACS
Electro-hydraulic DIACS
An electric DIACS is a DIACS where valve actuation, control and
sensor signals are transferred electric. There are no hydraulic
components included in the system. The electric DIACS valve is
actuated by an electric motor. Electric power and signals are
transferred through the same control line down hole.
A hydraulic operated DIACS is a DIACS where the valve actuation
is by hydraulic power supplied through control lines. Separate
electric or optical cables are applied for sensor signals to the
surface.
An electro-hydraulic DIACS system is a DIACS that apply a
redundant control line with hydraulic fluid for actuation of the
ICVs. All valves uses power from the same control line. The
hydraulic power to each valve is distributed by use of electrical
controlled solenoid valves. The actuation signals are sent through
an electric control line. The same electric control line is applied
for sending pressure and temperature data to the surface. A large
number of zones with valves and sensors can be controlled through
one single hydraulic and one single electric control line if no
redundancy is applied.
The DIACS systems are mainly assembled as an integrated part of
the completion string, and they are thus tubing retrievable (TR)
systems. A few of the inflow control valves from some of the
manufacturers can be installed as separate wireline retrievable
(WR) valves in side-pocket mandrels (SPM), allowing valve
replacement by wireline operations. Also separate sensor units or
modules may be installed in side-pocket mandrels and can thus be
retrieved and replaced by wireline. In order to be included in the
term DIACS, any system needs to have both remotely controlled
inflow valves and sensor units installed down hole. A system with
direct hydraulic operated inflow valves for one or several zones in
a well without any form of sensors will normally not be classified
as a DIACS, but simply as a zone inflow control system.
Standards
There are no general standards on DIACS or on the individual
components. One ISO standard covers some of the necessary
interfacing issues. That is ISO 13628-6: Petroleum and natural gas
industries Design and operation of subsea production systems Part
6: Subsea production control systems (2nd edition 2006). This
standard includes requirements and recommendation on how to
integrate and facilitate the control of intelligent well
completions or DIACS into the system architecture of subsea
production control systems, both with respect to the control
hardware and software functionality, such as interfacing,
communication protocols etc. In addition the IWIS joint industry
project (Intelligent Well Interface Standardization) has now issued
a Recommended Practice document (2007) on all relevant interfacing
issues regarding systems, technology and operation, including the
subsea X-mas tree system.
Synonyms
Synonyms for DIACS are:
Smart well completions
Intelligent wells
Abbreviations
Common shortenings related to DIACS are:
DIACS:
Down hole Instrumentation And Control System
HCM:
Hydraulic Control Module
ECM:
Electric Control Module
SPM:
Side Pocket Mandrel
ICV:
Inflow/Interval Control Valve
IWCS:
Intelligent well control system
IWE:
Intelligent well equipment
SEM:
Subsea electronic module
Downhole safety valve (DHSV)What is a downhole safety valve
The DHSV is a primary well barrier element located in the upper
completion string that consists of a valve unit and an actuator.
The purpose of the DHSV is to prevent uncontrolled flow of well
fluids from the reservoir and up the tubing in an emergency
situation by closing the valve.
The most common downhole safety valves are hydraulically opened
from the surface by applying pressure in a hydraulic control line
that is banded or clamped to the outside of the completion string.
The hydraulic pressure acts on a piston and moves a flow tube down
to open the valve. Valve opening will also compress a power spring.
This spring returns the valve to closed position when the control
line pressure is bled off. Most DHSVs today are using a flapper
valve mechanism to close the valve since this has proven by
experience to be the most reliable valve type. The flapper valve
also offers pump-through capabilities that are beneficial for
maintaining well control. The downhole safety valve will close in
three scenarios:
Close automatically when having a hydraulic power supply failure
(fail-safe-close)
Close automatically by the control system in an emergency
situation
Closed manually during regular valve leak testing and other
downhole operations
Types
The two major types of hydraulic operated downhole safety valves
with flapper are the tubing retrievable surface controlled
subsurface safety valve (TRSCSSV) and the wireline retrievable
surface controlled subsurface safety valve (WRSCSSV). An
introduction follows:
TRSCSSV
WRSCSSV
The above types of DHSVs dominate the market completely today.
Other less common types of DHSVs are available but not further
described in this database.
Configuration
DHSVs are used in all types of wells that are capable of flowing
to the surface or sea, including production wells and injection
wells. For wells with the X-mas tree located on the sea floor
(subsea wells) it is common to consider the use of two TRSCSSVs
with separate hydraulic control lines for the purpose of
redundancy. The Norwegian Petroleum Safety Authority also
stipulates that two downhole safety valves should be considered for
all subsea and high-pressure, high-temperature (HPHT) wells on the
Norwegian Continental Shelf. If only one TRSCSSV is installed, it
is normal to facilitate this with so-called WRSCSSV insert
capability.
Standards
A brief description of main content, requirements and acceptance
criteria in standards for downhole safety valves follow:
ISO 10432: Downhole equipment - Subsurface safety valve
equipment.
The latest edition is from 2004. ISO 10432 is identical to API
Spec 14A, 11th edition 2005. This standard specifies requirements
to factory acceptance testing (FAT), called functional testing in
this standard, and qualification tests (QT), called validation
testing in this standard, for new valves. Tests require both water
and nitrogen/gas as test medium. Maximum variations allowed in
opening and closing pressures are specified. Acceptance criteria
are:
Leak acceptance criteria gas: 0.14 Sm3/min
Leak acceptance criteria liquid : 10 cm3/min
Optional leak acceptance criteria gas: 0.014 Sm3/min (functional
test only)
Optional leak acceptance criteria liquid: 1 cm3/min (functional
test only)
ISO 10417: Subsurface safety valve systems -Design,
installation, operation & redress
The latest edition is from 2004. ISO 10417 is identical to API
RP 14B, 5th edition 2005. This standard gives main requirements to
installation, testing and acceptance criteria of the DHSV during
its operational lifetime in the well. Acceptance criteria are:
Leak acceptance criteria gas: 0.42 Sm3/min
Leak acceptance criteria liquid: 0.4 l/min
If the leak rate can not be measured directly, indirect
measurement by pressure monitoring of an enclosed volume downstream
of the valve shall be performed.
NORSOK D-010: Well integrity in Drilling and Well operations
The latest edition is from 2004. Section 15.8 specifies the
requirements to the DHSV as the primary well barrier to which all
DHSVs installed in wells on the Norwegian Continental Shelf (NCS)
and in Norwegian waters has to comply with, in accordance with the
Rules and Regulations set forth by the Norwegian Petroleum
Directorate (NPD). Test requirements and leak acceptance criteria
is the same as ISO 10417. Additional requirements in the D-010
standard are:
Regular testing: 30 minutes duration at maximum 70 bar (7 MPa)
across flapper
If the leak rate exceeds the acceptance criteria, the test can
be attempted three times to verify the valve status. If accept
criteria is still not met, further investigation and remedial
action shall be undertaken. Testing interval is monthly until three
consecutive qualified tests have been performed. Thereafter, every
three month until three consecutive qualified tests has been
performed month. Thereafter, every six month.
RF Sand slurry test procedure
Rogalands Research (now IRIS) has made a sand slurry test
procedure for safety valves. This is not a standard but a test
procedure for DHSV qualification testing. The sand slurry test
specified in ISO 10432 (Class 2 flow test) is often replaced by the
RF sand slurry test procedure by most of the Norwegian Continental
Shelf (NCS) operators. The procedure includes circulation tests and
slam tests with sand containing water, through a high number of
cycles and with valve operating cycles (opening/closing) and
flapper leak tests in between. Acceptance criteria are:
Leak acceptance criteria water: 10 cm3/min
Note that the nipple profiles and lock mandrels have other
standards for requirements to testing and qualification. But any
test of a WRSCSSV which includes loads on the valve assembly,
typically during slam tests, should be done with the WRSCSSV lock
mandrel and the WRSCSSV assembly locked into a relevant nipple
profile.
Abbreviations
Common names for downhole safety valves are:
DHSV:
Down Hole Safety Valve (all types)
SCSSV:
Surface Controlled Subsurface Safety Valve
SSCSV:
Sub Surface Controlled subsurface Safety Valve (storm
chokes)
SSSV:
Sub Surface Safety Valve
TRSCSSV:
Tubing Retrievable Surface Controlled Subsurface Safety
Valve
TRSV:
Tubing Retrievable Safety Valve
WRSCSSV:
Wireline Retrievable Surface Controlled Subsurface Safety
Valve
WRSSCSV:
Wireline Retrievable Sub Surface Controlled subsurface Safety
Valve
WRSV:
Wireline Retrievable Safety Valve
Annular safety valve (ASV)
What is an annular safety valve
The annulus safety valve is a barrier element integrated in the
tubing string and consists of a valve unit and a packer element
with hanger. The ASV is located below the downhole safety valve.
The main reason for this is to avoid the control line to the
downhole safety valve to go through the ASV. The purpose of the ASV
is to close the A-annulus to prevent flow of hydrocarbons from
A-annulus to surface. This will typically be the case in GLV
completions where gas is pumped into the A-annulus from the surface
and down to the gas lift injection point of the completion string.
Wells with gas lift pumped through A-annulus will typically have
50m3 of gas under high pressure accumulated in the A-annulus.
The packer element and the slips are set in the production
casing. The valve unit is located in a flow path that bypasses the
packer element. When the valve unit is closed the entire annulus is
sealed. When the valve unit is open, it is possible to flow annulus
through the packer bypass path. The valve unit of the ASV is
hydraulically operated, in the way that hydraulic control line
pressure is required to open the valve and keep it open. The valve
unit of the ASV is a fail safe close device and closes
automatically upon bleed-off or loss of the hydraulic control line
pressure.
Types
The type of ASV is determined from whether the packer with
hanger is an integral part of the ASV system or if the packer with
hanger is a separate tubing component from the valve itself. Both
systems are tubing retrievable (TR). Different designs exist from
the various manufacturers. The valve type is normally a sliding
sleeve type or a rod/piston type. The ASV with packer integrated
has either one control line for setting packer and operate the
valve or two control lines where one is used for packer setting and
one for valve control. The ASV and packer as separate completion
string components have one common control line.
Gas lift valve (GLV)What is a gas lift valve
A gas lift valve is a valve that enables injection of gas from
the A-annulus to the completion string. The purpose of the gas lift
valve is to provide artificial lift in the completion string and
thus increased production. Gas is injected into the A-annulus at
high pressure and further into the completion string through the
gas lift valve. The gas lift valve is located in a side pocket
mandrel (SPM) making it possible to retrieve thevalve without
pulling the entire completion string. The side pocket mandrel also
provides almost full bore in the completion string where the gas
lift valve is located. The gas injected into the completion string
will reduce the hydrostatic pressure inside the completion string
and thus increase the differential pressure between the reservoir
and the bottom of the well (increased drawdown). This will increase
the production rate and sometimes being a condition for even
starting the production. That could be a well with heavy and
viscous oil or a completion string filled with kill fluid. All gas
lift valves will have a check valve to prevent back flow from the
completion string to the annulus when reducing the pressure in
A-annulus. Gas lift valves located between the production packer
and the down hole safety valve should define the check valve as a
primary barrier. An alternative is to apply an annular safety
valve. All gas lift valves will also have a nozzle to regulate the
maximum gas injection rate.
Types
There are two main types of gas lift valves.
OperationalGLV
Unloading GLV
Configurations
Wells with high gas injection pressure available combined
withhigh pressure integrity of the completion string and the
production casing,can often have a single gas lift valve installed
and still haveacceptable lift. This valve will be anoperationalGLV.
Other wells with lowergas injection pressure available,less
pressure integrity of the completion string or production casing,
or need for a deep set valve to provide acceptable lift,will not be
able to open a singlegas lift valve at required depth. Such wells
must have one ormore unloading GLV's above the deepest setGLV
(which is the operational GLV) to assist in the process of getting
gas down to the operational GLV.The unloading valves are only
operational during production start-up.Whennormal production is
established, only the deep set operational GLV will circulate gas
from the A-annulus into the completion string.
Standards
A brief description of main content, requirements and acceptance
criteria in standards for production packers follow:
ISO 17078-2 Flow control devices for side-pocket mandrels
The latest edition is from 2000. The major issues in this
standard are:
Environmental service
Qualification testing (validation testing) procedure and
acceptance criteria
Factory acceptance test (functional testing) procedure and
acceptance criteria
Quality control
The standard is also specifying other issues like
specifications, documentation and storage. The standard has four
environmental service classes (E1 to E4). The standard for quality
control increases as the number increases. E4 will thus be the
highest quality level. That includes specification of the
environmental conditions by the purchaser not covered by E1, E2 and
E3. The standard has two quality control grades (Q1 to Q2). The
qualification testing of the design has three grades (V1 to V3).
The requirements become tougher as the number decreases. V1 will
thus have the toughest requirements. The factory acceptance testing
has three grades (F1 to F3). The requirements become tougher as the
number decreases. F1 will thus have the toughest requirements. The
standard for quality control increases as the number decreases. Q1
will thus be the highest quality level. Additional quality
requirements can of course be specified by the purchaser.
StatoilHydro test program
ISO 17078-2, table A-2, describes GLV testing requirements for
both design validation testing (qualification testing) and product
functional testing (factory acceptance testing). The test
procedures and acceptance criteria are described in ISO 17078,
annex E to N. ISO 17078-2, annex I, Back check testing, describes
testing requirements for the back check function. The back check
valves described in ISO 17078-2, annex I, are designed and intended
to prevent reverse flow through a flow control device. They are not
designed nor intended to be a part of the safety system, nor
provide a tight shut-off pressure safety seal. Thus, StatoilHydro
has worked out a test procedure with tougher requirements to accept
the GLV as a primary well barrier. There are two versions
available:
StatoilHydro procedure made by the main office
StatoilHydro procedure made for Tyrihans
The latter version has even tougher requirements for test
pressure and includes additional testing with increased flow rate
during unloading (displacement of the annular fluid). The unloading
test is also performed with particles.
Other related standards
Other related standards of relevance are:
ISO 17078-1: Side pocket mandrels ISO 17078-3: Running, pulling
and kickover tools and latches for side pocket mandrels ISO
17078-4: Practices for side pocket mandrels and related
equipment
Side pocket mandrel (SPM)
What is a side pocket mandrel
The side pocket mandrel is a completion string component that
has a receptacle bore or a side pocket machined or welded on
alongside the main SPM tubular conduit. The receptacle bore is
typically 1", 1" or 1 in diameter and is mainly used to house
inserted devices such as gas lift valves that require communication
with the annulus. The design of the side pocket mandrel is such
that the inserted device does not obstruct the main completion
string conduit, providing unrestricted access to completion string
components below. Components are normally inserted or pulled from
the SPM by wireline using a special kick-over type running tool,
which interact with dedicated tool orientation and manipulation
profiles found inside the SPM.
Figure 1: Side pocket mandrel
Permanent downhole gauge (PDG)
What is a permanent downhole gauge
A permanent downhole gauge is a sensor unit that is installed
integral to the completion string in a permanent gauge mandrel. The
sensor signal transmission is most commonly pressure or temperature
data and is through a signal line that runs from the permanent
gauge mandrel on the outside of the completion string in the
A-annulus and up through the tubing hanger and X-mas tree.
Types
The typical categories of downhole gauges are:
Quartz (piezoelectric)
Fiber optic
Capacitance
Strain
Venturi effect
The alternative to a PDG is to run temporary installed sensor
units on wireline that include a battery pack and internal memory
(so-called memory gauges).
Production packerWhat is a production packer
The production packer is a primary well barrier element located
in the bottom part of the upper completion string and consists of
an anchor mechanism, a packer element and an actuator. The
production packer is set inside the cemented part of the casing
during completion string installation. The purposes of the
production packer are to anchor the completion string to the casing
and to establish an isolated area between the casing and the
completion string above the production packer. This isolated area
is called the A-annulus.The components of the well below the
production packer are normally in contact with the reservoir
fluids. The production packer is actuated either mechanically or
hydraulically. Hydraulically set production packers are recommended
in deviated wells. The production packer actuator compresses the
entire anchor and packer assembly. The first step is expansion of
the anchor and the second step is expansion of the packer
element.
Types
It is normal to distinguish between permanent and retrievable
production packers. Both types are based on the same principle
design with a metal slips that anchor the packer to the casing wall
and an expandable packer element that provides seal against the
casing wall. An introduction follows:
Permanent production packers
Retrievable production packers
Some low-budget wells have a lower part of the completion string
that is cemented to the production casing. These solutions are not
described in this database.
Configurations
There is one production packer per well.
Standards
A brief description of main content, requirements and acceptance
criteria in standards for production packers follow:
ISO 14310: Downhole equipment Packers and bridge plugs
The latest edition is from 2001. This standard specifies the
following issues:
Quality control
Qualification testing (validation testing) procedure and
acceptance criteria
Factory acceptance test (functional testing) procedure and
acceptance criteria
Documentation
The standard has three quality control grades (Q1 to Q3). The
standard for quality control increases as the number decreases. Q1
will thus be the highest quality level. Additional quality
requirements can of course be specified by the purchaser. The
qualification testing of the design has seven grades (V0 to V6).
The requirements become tougher as the number decreases. V0 will
thus have the toughest requirements. The V3 grade has the toughest
requirements for liquid as test medium. The V0 and V1 grade has the
toughest requirements for gas as test medium. The V3, V1 and V0
grades include all the following combined loads:
Differential pressure
Axial load
Temperature cycling
The V0 grade has a zero bubble acceptance criteria. The V1 grade
has an acceptance criterion of maximum 20cm3 during a hold period
of minimum 15 minutes. The V3 grade has an acceptance criterion of
no more than 1% reduction in the maximum rated differential
pressure over the hold period after sufficient time has been
allowed for stabilisation. The V3, V1 and V0 grades also include
pressure reversal testing and require control of the casing ID used
during the test.
NORSOK D-010: Well integrity in Drilling and Well operations
The latest edition is from 2004. Section 15.7 specifies the
requirements to the production packer as the primary well barrier
to which all production packers installed in wells on the Norwegian
Continental Shelf (NCS) and in Norwegian waters has to comply with,
in accordance with the Rules and Regulations set forth by the
Norwegian Petroleum Directorate (NPD). Some additional requirements
in Norsok D-010 are:
The packer shall minimum be tested to V1 grade as described in
ISO 14310
Retrievable packers must be retrieved by mechanical
intervention
Retrieving by tubing manipulation is not allowed to
avoidaccidental activation
The packer must resist maximum expected design pressure
The maximum expected design pressure shall be based on worst
case scenario
Electrical submersible pump (ESP)What is an electrical
submersible pump
An electrical submersible pump is a downhole centrifugal pump
rotated by an electric motor to provide artificial lift in the
completion string and thus increased production. Most ESP'sare
installedat the end of the completion string and can only be
replacedby pulling the completion string.The ESPconsists of an
downhole high voltage electric AC motor connected to amulti-stage
centrifugal pump and with a power cable clamped to the outside of
the completion string from the downhole motor to the surface. Each
stage consists of a rotating impeller and a stationary diffuser.
The pumps are normally run at a fixed speed and have thus poor
flexibility. Therotational speed can however beregulated by
installing avariable frequency drive (VFD). The rotational speedis
3500 rpm at 60 Hz and 2915 rpm at 50 Hz.The frequency can be
regulated both higher and lower than these examples. ESP's are
commonly used for undersaturated oil wells andwells with high water
cut. Standardpumps can handlefluids with gas-oil-ratios (GOR) lower
than 100scf/stb (standard cubic feet/stock tank barrels), but
thisratio can be increased to about 1000 scf/stb combined with
downhole separationof free gas at the pump inlet. The gas separator
will remove the free gas from the produced fluid and vent this
gasto theA-annulus. Common problems are:
High motor temperature
Free gas in the fluid
Sand production
Scale on impellers
Bending of the pump
The ESP systems are however becoming more reliable due to
adequate well flow cooling of the electrical motor, high
temperaturemotor winding insulation, gas separator,measures to
prevent sand production (solids
