Knowing Subsurface Safety Valve- API14A
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<strong>Knowing</strong> <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong><br />
Equipment<br />
to <strong>API14A</strong> & FORM-175 IR454400<br />
Reading for my Aramco inspection knowledge.<br />
Shanghai 7<br />
th June 2018<br />
Charlie Chong/ Fion Zhang
闭 门 练 功<br />
Charlie Chong/ Fion Zhang
Charlie Chong/ Fion Zhang<br />
Fion Zhang at Shanghai<br />
Damuqiao 大 木 桥 路<br />
7 th June 2018
Charlie Chong/ Fion Zhang<br />
http://greekhouseoffonts.com/
The Magical <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong> Reading<br />
Charlie Chong/ Fion Zhang
Charlie Chong/ Fion Zhang
<strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong> (SSSV)<br />
Down Hole <strong>Safety</strong> <strong>Valve</strong> (DHSV)<br />
SSSV<br />
Charlie Chong/ Fion Zhang
Well Control<br />
Charlie Chong/ Fion Zhang<br />
https://www.youtube.com/embed/VW3yULTG9NY
Well Completion<br />
Charlie Chong/ Fion Zhang<br />
https://www.youtube.com/embed/iXdq65xzsus
PART:<br />
• <strong>Knowing</strong> <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong>s<br />
• API 14A<br />
• Form 175-454400<br />
Charlie Chong/ Fion Zhang
Part 1: <strong>Knowing</strong> <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong> (SSSV)<br />
A subsurface safety valve is essentially a shutdown valve installed at the<br />
upper wellbore for emergency shutdown to protect the production tubing and<br />
wellhead in case of overpressure. Purpose of a subsurface safety valve<br />
(SSSV) is to avoid the ultimate disaster which can result in release of<br />
reservoir fluids to the surroundings. This makes SSSV a very important<br />
component of a well completion.<br />
To protect the surface facilities in case of emergency, the wellbore is isolated<br />
from surface facilities using a subsurface safety valve (SSSV). Hence such a<br />
safety valve needs to be fail safe in order to isolate well bore in any kind of<br />
system failure or damage to surface production, control and safety facilities.<br />
Charlie Chong/ Fion Zhang<br />
http://www.enggcyclopedia.com/2012/02/subsurface-safety-valve-sssv/
Functioning of SSSV<br />
A subsurface safety valve is typically a uni-directional flapper valve, directed<br />
in such a way that the flappers open downwards when pressure is applied<br />
from an upward direction. The flapper can only open in the downward<br />
direction. So even if high pressure is applied by the well fluids from a<br />
downward direction, a safety valve can remain closed. This makes a<br />
subsurface safety valve fail-safe. To open the valve, hydraulic signal is sent<br />
from the surface well control panel. This hydraulic pressure is responsible for<br />
keeping the flappers of SSSV open and loss of hydraulic pressure result in<br />
closing of the valve. Thus wellbore can be isolated in case of system failure or<br />
damage to the surface facilities.<br />
Charlie Chong/ Fion Zhang
<strong>Subsurface</strong> <strong>Safety</strong><br />
<strong>Valve</strong> (SSSV)<br />
Charlie Chong/ Fion Zhang
<strong>Subsurface</strong> safety valves provide<br />
the ultimate protection against<br />
uncontrolled flow from producing oil<br />
and gas wells in case of<br />
catastrophic damage to wellhead<br />
equipment.<br />
Their use offshore is legislated in<br />
many parts of the world to protect<br />
people and the environment.<br />
<strong>Safety</strong> valves have evolved from<br />
the relatively simple downhole<br />
devices of the 1940s to complex<br />
systems that are integral<br />
components in offshore well<br />
completions worldwide.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
<strong>Subsurface</strong> safety systems provide emergency, fail-safe closure to stop fluid<br />
flow from a wellbore if surface valves or the wellhead itself are damaged or<br />
inoperable. <strong>Safety</strong> valves are essential in offshore wells and in many land<br />
wells located in sensitive environments, or in wells that produce hazardous<br />
gases. They are installed to protect people, the environment, petroleum<br />
reserves and surface facilities. Successful installation, dependable operation<br />
and reliability of safety-valve systems are crucial to efficient and safe well<br />
performance. Perhaps the most regulated component of an oil or gas well, the<br />
safety-valve system must satisfy stringent technical, quality and operational<br />
requirements. Scrutiny of safety-valve design, manufacture and operation by<br />
regulatory bodies and operators requires valve manufacturers to apply a level<br />
of diligence and testing beyond that of related well-completion and flowcontrol<br />
equipment. This reflects the crucial role of safety valves.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
The winds and waves of Hurricane Lili impacted about 800 offshore facilities,<br />
including platforms and drilling rigs, as the Category 4 storm passed through<br />
the oil-producing region offshore Louisiana, USA, in September and October<br />
of 2002. Despite sustained winds of 145 miles/hr [233 km/hr], the US Minerals<br />
Management Service (MMS) reported that the storm caused no fatalities or<br />
injuries to offshore workers, no fires and no major pollution. Six platforms and<br />
four exploration rigs were damaged substantially by the storm. There were<br />
nine reported leaks of oil; only two exceeded one barrel. None of these spills<br />
was associated with the six severely damaged platforms. Prevention of<br />
accidents is an important aspect of the MMS safety strategy. The lack of<br />
significant news relating to spills during this storm is a testament to the<br />
success of established safety protocols. As part of the safety system,<br />
subsurface safety valves serve a relatively unglamorous but critical role. By<br />
working properly when other systems fail, these valves are a final defense<br />
against the disaster of uncontrolled flow from a well.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Hurricane Lili<br />
Charlie Chong/ Fion Zhang
In principle, a safety valve is a simple device. Most of the time it is open to<br />
allow flow of produced fluids, but in an emergency situation it automatically<br />
closes and stops that flow. To effect this task, sophisticated engineering<br />
designs and state-of-the-art materials have been developed. The valve’s<br />
closure mechanism must close and seal after months of sitting in the open<br />
position and years after its installation.<br />
Special procedures and technologies applied to reopening the valve after<br />
closure ensure its continued reliability. Wells are drilled and completed under<br />
diverse conditions, so before an appropriate subsurface safety valve is<br />
selected and installed, a thorough review of the reservoir, wellbore and<br />
environmental conditions must be conducted.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
This analysis should consider these<br />
factors throughout the predicted life of<br />
a completion, if not the life of a well.<br />
Oil and gas developments in<br />
deepwater and high-pressure, hightemperature<br />
(HPHT) reservoirs impose<br />
additional engineering challenges in<br />
the design and installation of safety<br />
valves. In such environments, where<br />
well intervention is both difficult and<br />
costly often exceeding several million<br />
dollars, excluding lost production the<br />
importance of reliable safety-valve<br />
operation is even greater. This article<br />
reviews the evolution, design and<br />
installation of subsurface safety valves<br />
through examples from operations in<br />
the North Sea and Gulf of Mexico.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Disaster Drives Development<br />
The first safety device to control subsurface flow was used in US inland<br />
waters during the mid- 1940s. This Otis Engineering valve was dropped into<br />
the wellbore when a storm was imminent and acted as a check valve to shut<br />
off flow if the rate exceeded a predetermined value. A slickline unit had to be<br />
deployed to retrieve the valve. Those first valves were deployed only as<br />
needed, when a storm was expected.<br />
The use of subsurface safety valves was minimal until the state of Louisiana<br />
passed a law in 1949 requiring an automatic shutoff device below the<br />
wellhead in every producing well in its inland waters. Unfortunately, most<br />
disastrous situations occur unexpectedly. Surface facilities, including the<br />
surface safety systems, can be damaged by storms or vehicles impacting<br />
them. Boats dragging anchors or other devices can damage facilities on the<br />
bottoms of lakebeds or on the seafloor. Accidents have sometimes occurred<br />
when surface safety equipment is temporarily bypassed during logging and<br />
well intervention operations.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
The need for a new and more reliable type of subsurface safety valve was<br />
driven by accidents in Lake Maracaibo, Venezuela, in the mid-1950s. Tanker<br />
ships hitting platforms in the lake resulted in well blowouts. Producers wanted<br />
a valve that would protect the environment in case of severe damage to<br />
surface facilities, while maximizing production. The result was a surfacecontrolled<br />
valve that was normally closed—meaning the valve was closed<br />
unless an action kept it open. That action was fluid pressure transmitted to<br />
the valve through a hydraulic line from the surface.<br />
A 1969 blowout in a well in the Santa Barbara Channel off California, USA,<br />
led to 1974 regulations that required the use of subsurface safety systems on<br />
all offshore platforms and installations in US federal waters. These<br />
regulations relied on requirements and recommendations set forth by an<br />
American Petroleum Institute (API) task group comprising manufacturers and<br />
users of subsurface safety valves. The API has published key guidelines for<br />
many aspects of the design and completion of oil and gas wells.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Lake Maracaibo<br />
Charlie Chong/ Fion Zhang
Charlie Chong/ Fion Zhang
1969 Blowout In A Well In The Santa Barbara Channel Off California<br />
Charlie Chong/ Fion Zhang
The International Organization for Standardization (ISO) revised the work of<br />
the API task group to meet global needs. These ISO standards are widely<br />
applied for international offshore projects and also for many land-based<br />
developments. In the US, the MMS enforces the requirements of federal and<br />
state legislation. Similar government bodies, such as the Health and <strong>Safety</strong><br />
Executive in the UK and the Norwegian Petroleum Directorate in Norway,<br />
perform this function in their respective countries. Standards and<br />
recommendations developed by various industry collaborations have led to<br />
higher safety awareness and a greater commitment to mitigate human and<br />
environmental risk. This is critically important as the industry moves to exploit<br />
petroleum reserves in operating conditions that are significantly more<br />
demanding and severe, and environmentally more sensitive than those<br />
confronted in 1974. The challenges of safe oil and gas production in<br />
deepwater and HPHT reservoirs elevate industry collaboration efforts from<br />
beneficial to essential.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
<strong>Safety</strong>-<strong>Valve</strong> Operations<br />
Modern safety valves are an integral part of systems that protect almost all<br />
offshore production installations and a growing number of land based facilities.<br />
These systems protect people and the environment, and limit unwanted<br />
movement of produced fluids to the surface. As insurance against disaster,<br />
they must lie essentially dormant for extended periods, but be operational<br />
when needed. Development of today’s sophisticated valves occurred in<br />
distinct steps.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Early subsurface safety valves were actuated by a downhole change in<br />
production flow rate. A flow tube in such valves is equipped with a choke bean,<br />
which is a short, hard tube that restricts flow, creating a differential pressure<br />
between the top and bottom of the tube. Production fluid flowing through this<br />
choke creates a differential pressure across the bean—the pressure on the<br />
lower face of the choke bean is higher than the pressure on the upper face.<br />
When the force on the lower face exceeds the combination of pressure on<br />
the upper face and the force of the power spring holding the valve open, the<br />
flow tube moves up and allows the flapper to hinge into the flow stream and<br />
close against a seat, sealing off flow. The flow rate to close the valve can be<br />
set during manufacture by spring and spring-spacer selection and by<br />
adjusting the hole size through the bean.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Typical subsurface-controlled safety valve.<br />
Early safety valves were relatively simple in<br />
operation and created a significant restriction to<br />
production. The force of the valve spring, FS, acts<br />
on the flow tube to keep the flapper valve in a<br />
normally open position. The pressure below the<br />
restriction is P1 and that above is P2. These<br />
pressures act on the exposed faces of the piston,<br />
creating a force F1 – F2 to close the valve. When<br />
fluid flows upward, the constriction creates a<br />
pressure differential that increases closure<br />
force. The spring force is preset for a specific<br />
flow rate, so when the flow rate reaches that<br />
critical rate, the piston moves up, releasing the<br />
flapper to close and shut off fluid flow.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Typical subsurfacecontrolled<br />
safety valve.<br />
Early safety valves were<br />
relatively simple in operation<br />
and created a significant<br />
restriction to<br />
production. The force of the<br />
valve spring, FS, acts<br />
on the flow tube to keep the<br />
flapper valve in a normally<br />
open position. The pressure<br />
below the restriction is P1 and<br />
that above is P2. These<br />
pressures act on the exposed<br />
faces of the piston, creating a<br />
force F1 – F2 to close the<br />
valve. When fluid flows<br />
upward, the constriction<br />
creates a pressure differential<br />
that increases closure<br />
force. The spring force is<br />
preset for a specific flow rate,<br />
so when the flow rate reaches<br />
that critical rate, the piston<br />
moves up, releasing the<br />
flapper to close and shut off<br />
fluid flow.<br />
Charlie Chong/ Fion Zhang
<strong>Safety</strong> valves that are actuated in this manner create a restriction in the<br />
wellbore that can limit production even when they are open. For many years<br />
after the introduction of safety valves in the 1940s, proration was in effect in<br />
the US market, so wells typically were produced at rates lower than their<br />
maximum deliverability. A hindrance to well-production efficiency caused by<br />
valve design and installation was not considered a serious issue at that time.<br />
These downhole-actuated or subsurface controlled safety valves have two<br />
major limitations. Since a significant variation in fluid flow or pressure is<br />
required to actuate them, these valves can be used only when normal<br />
production is restricted to a level that is less than the maximum capability of a<br />
well. This actuation level is adjusted and set before the safety valve is<br />
installed in the wellbore. Also, since a significant flow-rate change is required<br />
to actuate the shutoff, the valve will not operate in low-flow conditions in<br />
which fluid flow is less than the preset production level.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
A new type of valve became necessary when energy markets changed during<br />
the 1970s, and more production was demanded from wells. However, when<br />
well productivity is maximized, it may be difficult or impossible to have enough<br />
additional flow downhole to overcome the spring force and close a<br />
subsurface-controlled safety valve. Under such conditions, reliable operation<br />
of flow-velocity type subsurface-controlled equipment can no longer be<br />
assured.<br />
Controlling safety-valve operation from a surface control station and effecting<br />
reliable closure independent of well conditions were key objectives for design<br />
engineers. In the early 1960s, Camco, now a part of Schlumberger,<br />
introduced surface-controlled subsurface safety-valve (SCSSV) systems to<br />
meet these needs. Later design improvements led to an internal valve profile<br />
that creates minimal disruption to fluid flow within the production conduit<br />
while the valve is open.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
An SCSSV is operated remotely through a control line that hydraulically<br />
connects the safety valve, up and through the wellhead, to an emergency<br />
shutdown system with hydraulic-pressure supply. The design is fail-safe:<br />
through the control line, hydraulic pressure is applied to keep the valve open<br />
during production. If the hydraulic pressure is lost, as would occur in a<br />
catastrophic event, the safety valve closes automatically through the action of<br />
an internal power-spring system—a normally-closed fail-safe design. With an<br />
SCSSV, activation no longer depends on downhole flow conditions. External<br />
control also allows the valve to be tested when desired, an important<br />
improvement for a device that may be installed for years before its primary<br />
use is required.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Surface-controlled subsurface safety valve<br />
(SCSSV). The more recent SCSSV design is a<br />
normally closed valve, with the spring force, FS,<br />
acting to push the piston upward and release the<br />
flapper to close the valve. Control pressure<br />
transmitted from surface through a hydrauliccontrol<br />
line acts against the spring to keep the<br />
flapper valve open during production. This<br />
concentric- piston design, which has been<br />
replaced in many modern valves by a rod-piston<br />
design, has a ring-shaped area between the<br />
piston and the valve body that the hydraulic<br />
pressure acts upon to generate the opening<br />
force FH. The small difference in the piston-wall<br />
cross sections between the upper (U) and lower<br />
(L) faces of the piston adds a small additional<br />
upward force, FL – FU.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Charlie Chong/ Fion Zhang
Surface-controlled subsurface safety valve (SCSSV).<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Closure systems<br />
Early safety-valve closure mechanisms typically had two main designs:<br />
• ball or<br />
• flapper-valve assembly.<br />
The ball-valve design is a sphere, the ball with a large hole through it. When<br />
this hole is aligned with the production tubing, flow is unimpeded. Rotating<br />
the ball 90˚ blocks flow. Ball valves are mechanically more complex to<br />
operate since linear movement of the control mechanism, often a piston,<br />
must be converted into rotational motion of the ball on the seal. The ballvalve<br />
mechanism also is sensitive to an increase in friction caused by debris<br />
or accumulations of scale or paraffin.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
The flapper-valve design, pioneered by Camco in the late 1950s, has become<br />
the most commonly used closure mechanism in the industry, including the<br />
challenging severe-service applications where reliability over the life of a well<br />
is required. A flapper acts like a door. A flow tube moves in one direction to<br />
push the flapper open and allow flow through the valve. Moving the flow tube<br />
back from the flapper allows a torsion spring to close the valve and block flow.<br />
Charlie Chong/ Fion Zhang<br />
https://production-technology.org/subsurface-safety-valve/
A flapper-valve mechanism is less susceptible to malfunction than a ballvalve<br />
assembly and offers several advantages during operation. Debris in the<br />
flow stream and solids buildup from scale or paraffin are less likely to prevent<br />
closure of a flapper valve than a ball valve. A ball valve can be damaged<br />
more easily by a dropped wireline tool or other equipment lost in the wellbore.<br />
Fluids can be pumped through flapper valves without damage to the flapper<br />
sealing surface. The primary function of a subsurface safety valve is to close<br />
and block flow when emergency conditions require halting well production.<br />
The API has set an acceptable leakage rate of 5 scf/min [0.14 m3/min] for<br />
newly manufactured subsurface safety valves. This is considered sufficient to<br />
contain the wellbore pressure.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Schlumberger valves are tested to a more stringent standard than that<br />
required by the API specifications. A valve must close against 200 and 1200<br />
psi [1.4 and 8.3 MPa], and no more than one bubble of nitrogen can escape<br />
within 30 seconds at either test pressure differential.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Key features of ball and<br />
flapper valves. A ball valve<br />
has a sphere with a hole<br />
through it, allowing flow<br />
through the valve when the<br />
hole is aligned with the tubing.<br />
Rotating the ball 90˚ places<br />
the solid part of the ball in the<br />
flow stream, stopping flow<br />
(top). The more common<br />
flapper valve works like a<br />
hinge with a spring. When the<br />
flow tube is down, the flapper<br />
is open, and when it is pulled<br />
up, the flapper closes<br />
(bottom).<br />
Charlie Chong/ Fion Zhang
Typical safety-valve self-equalization mechanism. Manufactured from<br />
erosion-resistant materials, a self-equalization system is designed to operate<br />
on a fail-safe basis with minimal interruption to the overall integrity and<br />
operating reliability of the safety valve.<br />
Note: Self-equalizing mechanism: An integral equalizing mechanism<br />
eliminates the need to equalize differential pressure across the flapper. By<br />
venting shut-in pressure from below the safety valve to the tubing above the<br />
flapper, a valve can be equalized and can return the well to production<br />
quicker, safer, and more efficiently than when pumps and fluids must be used.<br />
Particularly effective is a through-the-flapper, metal-to-metal self-equalizing<br />
system that eliminates valve failure caused by erosion problems or buildup of<br />
fluid debris in the valve annulus.<br />
Charlie Chong/ Fion Zhang<br />
https://www.offshore-mag.com/articles/print/volume-57/issue-11/news/general-interest/improving-subsurface-safety-valve-reliability-a-problem-solution-approach.html
Flapper Type SSV<br />
https://www.youtube.com/embed/XByZEGbRgcM<br />
Charlie Chong/ Fion Zhang
When the flapper is closed, as shown in the tool diagram and in the inset<br />
(left), the dart (red) rests in a seat and the flow tube (tan) is slightly above the<br />
flapper seal. A small increase in control pressure moves the flow tube down<br />
slightly and opens a flow path around the dart (middle). When the pressures<br />
above and below the flapper are equalized, the flow tube moves down to fully<br />
open the flapper valve, and the dart moves into another seat (right).<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Charlie Chong/ Fion Zhang
SCSSV<br />
Charlie Chong/ Fion Zhang<br />
https://seabed.software.slb.com/production/WebHelp/production_model/domain_introduction/tubing_and_packers.htm
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
After actuation - After an<br />
incident that activates a safety<br />
valve, it may be necessary to<br />
pump weighted fluids downhole<br />
to control, or kill, the well.<br />
<strong>Safety</strong> valves are usually<br />
installed above most other<br />
downhole assemblies, so a<br />
method is needed to pass kill<br />
fluids through a closed safety<br />
valve. The increased pressure<br />
provided by pumping the wellcontrol<br />
fluids will open a flapper<br />
valve and allow fluids to pass<br />
easily through the safety-valve<br />
assembly.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Once the kill-weight fluids are in place the flapper valve’s torsion spring will<br />
return it to the closed position. When it is time to put a well back on<br />
production, the safety valve must be reopened. Typically, the positive<br />
pressure from below holds the subsurface safety valve closed. In the earliest<br />
and simplest designs, tubing pressure was applied from surface to open the<br />
valve, but delivering the pressure required may be inconvenient or impractical<br />
due to availability of equipment or time and cost constraints.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Flapper-type safety valves today include an actuation mechanism that opens<br />
the valve using a small pressure differential that does not damage the closure<br />
mechanism. Self-equalizing valves use the same actuation mechanism and<br />
also feature a mechanism to simplify equalizing pressure from above and<br />
below the closed flapper (previous page, right). When the self-equalizing<br />
valve is closed, there is a gap between the lower end of the flow tube and the<br />
flapper. A small increase in control-line pressure moves the flow tube down<br />
enough to unseat the equalizing dart, which opens a small flow path to the<br />
production tubing below the flapper. The pressure equalizes above and below<br />
the flapper, allowing the valve to open smoothly. The self-equalization<br />
mechanisms in ball valve designs require application of a high hydraulic<br />
pressure that may damage the more complex closure system inherent in<br />
these types of valves.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Pressure Self-Equalizing Technology<br />
A subsurface safety valve will experience around one hundred slam<br />
processes during its lifetime. One of the fatal failure modes happening after<br />
such a closure of the flapper safety valve is its inability to open again. This<br />
failure occurs because of the extreme high pressure built up from the<br />
reservoir side, which can be much higher than the maximum hydraulic<br />
pressure supplied to open the flapper. One way to solve this problem is to drill<br />
open the dead flapper and superimpose a smaller valve to replace it.<br />
Although this remedy reduces the production rate of the well, it is still much<br />
better than killing the whole production string. Another way to solve this<br />
problem is by adding a pressure self-equalizing mechanism to the subsurface<br />
safety valve. The new design feature has been widely adopted by various<br />
industrial subsurface safety valve designers. Although detailed designs may<br />
vary from each other, the underlying ideas are quite similar.<br />
Charlie Chong/ Fion Zhang<br />
https://www.rpsea.org/sites/default/files/RPSEADOC/07121-1603c-TH-Design_Study_Flapper_Style_SSSV_XHPHT_Applications-11-01-09_P.pdf
One such design is shown in the Figure 2.4. As shown in Figure 2.4, the<br />
sleeve tube will first push the poppet to the other side of the flapper. This will<br />
create a small channel for the flow to pass through the flapper, which helps to<br />
decrease the pressure differential. When the flapper is fully opened, the outer<br />
tube will push the plunger as well as the poppet back to its original position.<br />
However, every additional moving part will reduce the reliability of the<br />
subsurface safety valve. Possible fluid leakage and functional failure should<br />
be considered when including the pressure self-equalizing mechanism. In<br />
other words, a flapper design without pressure self-equalizing feature is more<br />
reliable than the one with such a feature.<br />
Charlie Chong/ Fion Zhang<br />
https://www.rpsea.org/sites/default/files/RPSEADOC/07121-1603c-TH-Design_Study_Flapper_Style_SSSV_XHPHT_Applications-11-01-09_P.pdf
The potential drawback of a pressure equalization system is that any<br />
mechanism or fluid path that bypasses the closure assembly presents a<br />
potential leak path that may contribute to safety-valve failure or malfunction.<br />
This potential is minimized as much as possible through rigorous designs and<br />
manufacturing methods that set high standards for accuracy, reliability and<br />
quality assurance. In certain applications, the functionality of an internal<br />
pressure-equalizing mechanism is an essential completion-design feature. It<br />
may not be possible to equalize pressure against a closed valve by pumping<br />
fluid into the wellbore at surface. For example, on isolated or remote wells, it<br />
may be difficult and expensive to pump fluid into a wellbore when needed; the<br />
equipment may not be readily available or may be expensive to transport to<br />
the location. For these wells, a selfequalizing valve may be used to minimize<br />
the pressure required at surface. Generally, the preferred option is to<br />
minimize use of self-equalizing systems during well design by selecting<br />
applications and operational procedures that do not require such valves.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Halliburton <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong><br />
Charlie Chong/ Fion Zhang<br />
https://www.youtube.com/embed/EcdAa-lYGKw
Baker Hughes <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong><br />
Charlie Chong/ Fion Zhang<br />
https://www.youtube.com/embed/u-6q8uWInuQ
Conveyance systems - There are two typical methods for conveying and<br />
retrieving safety valves: tubing and slickline. The method chosen for a<br />
downhole application influences valve geometry and its effect on fluid flow<br />
from the wellbore.<br />
■ Tubing-conveyed, tubing-retrievable safety valves are designed to be an<br />
integral component of the production-tubing string and are installed during<br />
well completion with the tubular and other downhole equipment. For surface<br />
controlled valves, the hydraulic-control line to surface is attached directly to<br />
the safety valve and secured to the production-tubing string as it is run into<br />
the wellbore. The primary benefit of tubing-retrievable valves is that<br />
production is unhindered; the safety-valve internal diameter is essentially<br />
equivalent to that of the production tubing. The full-diameter bore also<br />
permits access to the lower wellbore with tools and instruments for flow<br />
control, well monitoring or service.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Tubing-conveyed- Tubing-retrievable<br />
Surface Controlled <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong>s<br />
Charlie Chong/ Fion Zhang<br />
https://waset.org/publications/10006298/teaching-material-books-publications-versus-the-practice-myths-and-truths-about-installation-and-use-of-downhole-safety-valve
■ Slickline-conveyed, slickline-retrievable safety-valve assembly is placed in<br />
the wellbore after the production-tubing string and surface wellhead<br />
equipment have been installed. It seats and locks into a special landing<br />
nipple that was placed in the production-tubing string at the desired setting<br />
depth, either as a component of the tubing string or as an integral element of<br />
the design of a tubing-conveyed safety valve. The landing nipple has a<br />
control line to surface to provide hydraulic pressure for operating the valve. In<br />
most cases, slickline- retrievable valves are easier and less expensive to<br />
remove from the wellbore or maintenance or inspection than tubingretrievable<br />
designs.<br />
Most tubing- retrievable valves are designed to use slickline-retrievable<br />
valves as a secondary system; if such a tubing retrievable valve malfunctions,<br />
the slickline retrievable valve can be installed until the next planned workover<br />
that requires tubing to be pulled. In a small percentage of completions, a<br />
slickline- conveyed valve system is used as the primary safety valve.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
A slickline- retrievable SCSSV must have a pressure connection with the<br />
hydraulic-control line from surface. The landing nipple has two polished<br />
areas on either side of hydraulic port. Sealing elements on the outside of the<br />
slickline retrievable valve mate with these polished bores in the nipple. Once<br />
a valve is locked in place, the seals contain the hydraulic pressure and<br />
separate it from wellbore fluids.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Slick Line retrievable<br />
Surface Controlled <strong>Subsurface</strong> <strong>Safety</strong> <strong>Valve</strong>s<br />
Charlie Chong/ Fion Zhang<br />
https://waset.org/publications/10006298/teaching-material-books-publications-versus-the-practice-myths-and-truths-about-installation-and-use-of-downhole-safety-valve
Comparison of slickline- and tubing-retrievable safety-valve systems. The<br />
slickline-retrievable system typically locks into a landing nipple in the<br />
completion string and seals on either side of the control-line port to isolate the<br />
control fluid from wellbore fluids (left). The tubing-retrievable system is an<br />
integral part of the completion string (right). The inside diameter of the valve<br />
is similar to the inside diameter of the production tubing.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Slickline- Retrievable SCSSV<br />
https://www.youtube.com/embed/LmDJQW2OxyY<br />
Charlie Chong/ Fion Zhang
Flapper Type SSV<br />
CTR's Tubing Retrievable Surface Controlled Sub Surface <strong>Safety</strong> <strong>Valve</strong> (TRSCSSSV) is piston<br />
rod activated flapper-type safety valve which is designed to shut in a well at a point below the<br />
surface.<br />
Charlie Chong/ Fion Zhang<br />
https://www.ctr.as/completion
Surface Controlled SSV- Flapper Type SSV<br />
Charlie Chong/ Fion Zhang<br />
https://www.ctr.as/completion
the<br />
Surface Controlled SSV- Flapper Type SSV<br />
Charlie Chong/ Fion Zhang
Weatherford Slickline Retrievable SCSSV<br />
Charlie Chong/ Fion Zhang
Material selection - In a wellbore environment, where fluids can be corrosive<br />
or erosive, and have the potential to precipitate scale and organic solids, it is<br />
difficult for any downhole equipment to maintain a high degree of readiness<br />
and reliability over an extended period of time.<br />
Flow-wetted parts, which are in contact with production fluids, must be<br />
designed to resist corrosion, erosion and the buildup of precipitates or solids.<br />
Flow-wetted surfaces of Schlumberger subsurface safety valves can be<br />
protected with a surface treatment of ScaleGard scale-deposition resistant<br />
coating. This is a Teflon- based product with an enhanced binder that is<br />
applied to surfaces by a spray and bake process. The 0.0013- to 0.002-mm<br />
(1.3μm-2.0μm ) (0.00005- to 0.00008-in.) thick coating does not interfere with<br />
the operation of completion- equipment assemblies with moving or<br />
reciprocating parts, and is slightly flexible.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
A ScaleGard treatment imparts the same excellent friction-reduction<br />
properties as Teflon material even under conditions of poor lubrication. Scale,<br />
which comprises various inorganic salts that precipitate from aqueous<br />
solution, resists adhering to parts with ScaleGard protection since Teflon<br />
surfaces resist wetting by both aqueous and organic solutions. ScaleGard<br />
coatings also have excellent chemical and heat resistance. Material selection,<br />
component design and the coating of flow-wetted parts contribute to the<br />
effectiveness and dependability of subsurface safety valves.<br />
The Camco* TRM-4 and -4H series tubing-retrievable, surface controlled,<br />
subsurface safety valves with ScaleGard protection .<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/completions/product_sheets/safety_valves/trm_4_series_reduced.pdf
<strong>Valve</strong>-System Integrity<br />
In the past, safety-valve systems have malfunctioned because of failure or<br />
problems with components other than the SCSSV itself. For piston and<br />
flapper components in the device to operate properly, the control line, control<br />
fluid and surface control systems also must be designed, manufactured,<br />
installed and maintained properly. Small amounts of debris in the hydraulic<br />
control fluid have caused safety-valve systems to malfunction. The primary<br />
protection from this reliability hazard is to provide operating personnel with<br />
the facilities and training to apply high standards for operating and<br />
maintaining a subsurface safety system throughout its life. Additional<br />
protection comes from Schlumberger control-fluid filtering systems that can<br />
be installed in surface and downhole equipment to minimize this risk. Several<br />
deepwater safetyvalve designs now include this filtering system as an integral<br />
component to ensure operational integrity for the life of a well installation.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
The safety-valve control fluid must function properly throughout exposure to a<br />
wide range of temperatures and pressures. The fluid must maintain viscosity,<br />
lubricity and general conditions that ensure continuous satisfactory operation<br />
of a safety valve. The closing time for a safety valve—time elapsed between<br />
initiating action at the surface controls and valve closure—depends largely on<br />
• safety-valve design and<br />
• setting depth, and<br />
• viscosity of the control fluid.<br />
A control fluid must be matched to all anticipated operating conditions to<br />
ensure optimized performance of a safety valve. Historically, oil-base control<br />
fluids have been used. However, the control systems used for modern well<br />
systems often are designed to vent control pressure at the seafloor to reduce<br />
operating response time. Environmentally safe, water-base control fluids were<br />
developed for this function, and they typically maintain the high performance<br />
requirements of oil-base control fluids. Synthetic fluids are now available for<br />
situations in which the operating environment exceeds the chemical and<br />
temperature capabilities of water- or oil-base fluids.<br />
Charlie Chong/ Fion Zhang
Functional Testing<br />
<strong>Safety</strong> valves typically undergo functional testing to API specifications at the<br />
time of manufacture; many local governmental bodies regulate and require<br />
such testing. Since operational sensitivities vary by type of valve, model and<br />
manufacturer, the specific operating manual must be consulted to establish<br />
operational procedures and constraints for a specific valve design. Advanced<br />
safety-valve systems should be engineered to handle a valve malfunction, so<br />
safe production can resume as quickly as possible. Many regulatory bodies<br />
prohibit production without a functional safety-valve system. The well should<br />
have contingency tools in place, with modes of operation prepared to resume<br />
or continue production safely until the next scheduled major intervention or<br />
workover. For example, as a contingency, some tubing-retrievable safety<br />
valve systems are designed to be locked open and have a slicklineretrievable<br />
safety-valve assembly inserted to use the same control system,<br />
as described above. Although the secondary valve assembly may restrict<br />
flow somewhat, production can be continued while preserving the necessary<br />
functionality for well safety.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Heavy-wall Flow Couplings<br />
Turbulent flow can generate material loss from tubular walls above and below<br />
a restriction or profile change in production tubular, such as may occur with a<br />
safety valve. Heavy-wall flow couplings often are installed in the tubing<br />
above and below safety-valve assemblies to protect the string from damaging<br />
erosion at these points. Flow couplings are always recommended—in some<br />
cases required by regulation—with slickline- retrievable safety-valve<br />
assemblies, because of the greater restriction and increased turbulence<br />
created by the change in internal profile of the flow conduits.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Bruce field,<br />
offshore Aberdeen,<br />
Scotland. On the right<br />
is a Bruce field<br />
wellbore design. The<br />
SCSSV is placed at<br />
the shallow depth of<br />
937 ft [286 m].<br />
Chemical-injection<br />
mandrels are much<br />
lower in the well.<br />
Charlie Chong/ Fion Zhang<br />
https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf
Bruce field<br />
Charlie Chong/ Fion Zhang
Bruce field<br />
Charlie Chong/ Fion Zhang
Optimizing Flow Safely<br />
A systems approach frequently is used to select production tubulars and<br />
completion components for oil and gas wells. This ensures that the overall<br />
performance of the assembled completion string is compatible with reservoir<br />
deliverability and that the conduit between the reservoir and surface facilities<br />
is efficient. Completions are designed to minimize the effects of corrosion and<br />
erosion to be expected from produced fluids and solids. Production conditions<br />
can change or may exceed expected performance such that it may be<br />
possible to produce a well at rates higher than anticipated. Production<br />
engineers then have two options if they wish to use the existing completion:<br />
constrain production according to the limitations of the original completion<br />
design; or investigate how production levels can be increased while<br />
maintaining an acceptable safety factor within the limits of installed equipment.<br />
Charlie Chong/ Fion Zhang
BP adopted the latter approach for gas wells in the Bruce field, located in the<br />
northern North Sea (previous page). Development began in 1992, with first oil<br />
and gas produced in 1993. A study to assess the impact of production<br />
changes on safety-valve operation focused on subsea wells completed in the<br />
late 1990s with 51⁄2-in. tubing and Camco TRM-4PE tubing-retrievable safety<br />
valves. This valve design incorporates non elastomeric dynamic seals—made<br />
of a spring-energized filled Teflon material—and a self-equalizing system<br />
(right). Well testing and early production data supported a rock-mechanics<br />
finding that the Bruce reservoir formation was competent and had minimal<br />
potential for sand production. Recently revised operating guidelines adopted<br />
by BP at Bruce field had identified 230 ft/sec [70 m/s] as the maximum fluid<br />
velocity for nominal solids-free gas production (sand production
TRM-4PE safety-valve<br />
assembly used in the Bruce<br />
field. The tubing retrievable<br />
TRM series has a compact<br />
and simple design suitable for<br />
a wide range of completion<br />
types. The number of seals<br />
and connections incorporated<br />
within the valve assembly is<br />
minimized to reduce the risk<br />
of leakage.<br />
Charlie Chong/ Fion Zhang
Gas Slam Testing<br />
BP estimated that the additional production allowed by increasing the fluidvelocity<br />
limit from 110 to 230 ft/sec on the Bruce field wells would be 15 to 20<br />
MMscf/D [425,000 to 566,000 m3/d] for each well. Recompletion or workover<br />
to allow this increase in production was not considered feasible, so the limits<br />
on SCSSV performance and capability were re-evaluated. Operational testing<br />
of subsurface safety valves under flowing conditions, known as gas slam<br />
testing, is routinely performed as part of the product design-validation process,<br />
using API and ISO specifications. These standard tests are performed at<br />
relatively low flow rates—tens of feet per second.<br />
Charlie Chong/ Fion Zhang
For higher gas flow-rate conditions, specialized equipment is required to slam<br />
test valves and monitor valve performance. The previous Schlumberger flowrate<br />
restriction of 110 ft/sec for operation of the TRM-4PE-series safety valve<br />
was set using these conventional design tests. Additional safety-valve slam<br />
tests were performed at the BG Technology Limited test facility at Bishop<br />
Auckland in the UK, one of only three facilities worldwide capable of<br />
performing such gas-slam tests under conditions that are as close as possible<br />
to Bruce field conditions. The primary objective of these tests was to<br />
determine if the TRM-4PE-series safety valves could be safely and reliably<br />
used at producing conditions of 230 ft/sec.<br />
Part of this process established the maximum gas-flow velocity against which<br />
the safety valve will slam closed multiple times while maintaining reliable<br />
operation and sealing to an acceptable leak rate—the specified API<br />
allowable leak rate of 5 scf/min. Reliable operation is determined by<br />
measuring repeatable and consistent valve hydraulic operating pressures.<br />
The gas-slam-testing procedure and associated instrumentation were<br />
designed to monitor performance of key safety-valve components including<br />
the flapper and seat mechanism, hydraulic system and equalizing valveactivation<br />
mechanism.<br />
Charlie Chong/ Fion Zhang
<strong>Valve</strong> closure was tested at a series of mass flow rates with visual inspection<br />
of critical components after each test series. Initial tests at 110 ft/sec were<br />
first conducted to establish a baseline for the operating performance of the<br />
valve hydraulic system and closure mechanism. Staged increases in mass<br />
flow rate were applied (below). Precise measurements of leakage were made<br />
upon initial closure and again following five open and close cycles. The goal<br />
was to successfully test the safety valve at 230 ft/sec. This was achieved, and<br />
additional, more aggressive flow rates were applied to establish the limit of<br />
the current valve design. Tests of 400 ft/sec [122 m/s] were successfully<br />
applied to effect closure, although the rate of 350 ft/sec [107 m/s] was<br />
deemed to be the reliable limit of operation for the standard valve<br />
components in use.<br />
Charlie Chong/ Fion Zhang
Gas Slam Testing<br />
* The specified API allowable leak rate is 5 scf/min [0.14 m 3 /min]<br />
Charlie Chong/ Fion Zhang
As a result of testing performed on the safety valve and the engineering<br />
study conducted on the completion system, the production- rate limit for the<br />
applicable Bruce field wells was increased from 110 to 230 ft/sec. This<br />
increase was made with the knowledge that equipment performance was<br />
assured and that any questions relating to the safety or security of the well<br />
had been successfully resolved. After 12 months, the incremental rate benefit<br />
from each of the rate-constrained wells in the Bruce field was 9 MMscf/D<br />
[255,000 m3/d] and 400 B/D [63.6 m3/d]. In addition, the test results imply<br />
rate increases may be considered for additional completions with similar<br />
SCSSV installations.<br />
Charlie Chong/ Fion Zhang
<strong>Valve</strong>-System Considerations<br />
Since the 1980s, several oil and gas companies have collaborated on a major<br />
study of SCSSV reliability, including data from valve manufacturers and<br />
operating companies with offshore interests in Brazil, Denmark, The<br />
Netherlands, Norway and the UK. The study, originally undertaken by the<br />
Foundation for Scientific and Industrial Research at the Norwegian Institute of<br />
Technology (SINTEF) and currently managed by Wellmaster, remains the<br />
largest yet undertaken into subsurface safety-valve operational experience.<br />
Conclusions of the SINTEF report from 1989 have influenced safety-valve<br />
development in the years since. These conclusions include the following<br />
findings:<br />
• Tubing-retrievable safety valves are more reliable than slicklineretrievable<br />
valves.<br />
• Flapper valves are more reliable than ball valves.<br />
• Non-equalizing valves are more reliable than self-equalizing valves.<br />
• The need for routine functional testing to identify problems should be<br />
balanced against the risk of imposing conditions or damage during testing<br />
that affect the operation or reliability of safety valves.<br />
Charlie Chong/ Fion Zhang
SINTEF<br />
Visit of the Vresova IGCC power plant with representatives of Czech Technical University, SINTEF Energy Research and the<br />
Norwegian Research Council (Photo: SINTEF Energy)<br />
Charlie Chong/ Fion Zhang<br />
https://blog.sintef.com/sintefenergy/ccs/eea-project-we-are-cooperating-with-to-promote-implementation-of-ccs-in-the-czech-republic/
Advances in materials science and component design coupled with superior<br />
quality assurance in materials and construction continue to improve the<br />
reliability of safety-valve systems while meeting the stringent gas-slam testing<br />
requirements and need for large dimensions for flow of modern highproduction<br />
well designs.<br />
The SINTEF and Wellmaster studies show that mean time to failure MTTF of<br />
tubing-retrievable flapper valves improved from 14 years in 1983 to more than<br />
36 years in a 1999 study.<br />
Charlie Chong/ Fion Zhang
Technical and economic influences drive the development of technology in<br />
different ways. Current subsurface safety-valve application categories can be<br />
segmented broadly as:<br />
• conventional,<br />
• HPHT and<br />
• deepwater.<br />
Conventional safety-valve systems are installed in predictable or known<br />
wellbore conditions and require little or no specialist engineering or materials.<br />
Operators anticipate such wells will have some form of economically viable<br />
well intervention during their life, which typically is less than that of advanced<br />
wells for which intervention is not planned or feasible. The key driver in<br />
selecting components in a conventional installation is reliability at an<br />
economic price. Completion designs for HPHT and deepwater environments<br />
have a higher standard of reliability, with an emphasis on safe and efficient<br />
operation that optimizes production from the reservoir through the entire life<br />
of a well. These more extreme applications require proven design concepts<br />
that minimize the number of seals and connections to reduce potential leak<br />
paths, and use materials that will be unaffected by the anticipated<br />
environment and applied loads throughout the life of a valve.<br />
Charlie Chong/ Fion Zhang
These more extreme applications require:<br />
• proven design concepts that<br />
• minimize the number of seals and connections to reduce potential leak<br />
paths, and<br />
• use materials that will be unaffected by the anticipated environment and<br />
applied loads throughout the life of a valve.<br />
Charlie Chong/ Fion Zhang
Interventions are becoming more costly, even when they are planned in<br />
advance. Well-completion components must last over increasingly extended<br />
periods. The costs, complexity and hazards caused by initiation of workover<br />
operations or slickline interventions may be prohibitive on subsea wells. The<br />
engineering and quality assurance activities for such demanding and<br />
interdependent design conditions typically require solutions to be developed<br />
on a case-by-case or project basis. Engineers and designers of downhole<br />
equipment are under constant pressure to make the most of available<br />
wellbore geometry without sacrificing reliability or system value. Casing size<br />
is largely determined by drilling conditions, so engineers who design<br />
completion equipment, including safety valves, must provide the desired<br />
functionality without sacrificing available flow area in the production conduit.<br />
High-strength materials allow reduction in the wall thickness of components,<br />
although compatibility with any potentially corrosive fluids in a wellbore also<br />
must be examined.<br />
Charlie Chong/ Fion Zhang
Similarly, designing valves for HPHT installations requires a more rugged<br />
construction for load- or pressure-bearing components. Advanced material<br />
selection and component design are the key tools in resolving this problem.<br />
The innovative curved flapper closure system is one example of how creative<br />
design engineers have managed to increase the safety-valve internal<br />
diameter without increasing the external dimensions of a valve assembly<br />
(below). <strong>Safety</strong> valves with curved flappers match the internal and outside<br />
diameters of smaller casing sizes better than previously thought possible.<br />
Charlie Chong/ Fion Zhang
<strong>Safety</strong>-valve curved flapper. The<br />
curved flapper design allows a<br />
larger inside diameter for the<br />
production conduit. The wings of<br />
the flapper are profiled to fit within<br />
a smaller radius than would be<br />
possible with a conventional flatflapper<br />
design. This can offer<br />
important advantages when<br />
wellbore or safety-valve geometry<br />
is critical.<br />
Charlie Chong/ Fion Zhang
Setting <strong>Valve</strong>s at Great Depth<br />
The depth for placing an SCSSV is limited by the hydraulic working area<br />
required to effect closure of the valve. Today, essentially all subsurface safety<br />
valves are normally closed valves, requiring a positive force to keep them<br />
open.<br />
That force is supplied by pressure in the hydraulic-control line to surface, but<br />
the constant force that is applied is the hydrostatic pressure of the fluid in the<br />
hydraulic line. In the event of control-line leakage, the control pressure could<br />
increase if a denser fluid from the tubing annulus leaks into the control line.<br />
To ensure fail-safe operation, the closing pressure of a safety- valve spring<br />
mechanism must exceed the pressure potentially applied in either of these<br />
cases.<br />
Charlie Chong/ Fion Zhang
Camco introduced a rod-piston actuation system in 1978 that has been<br />
adopted by the industry for both tubing- and wireline- retrievable valves .<br />
The hydraulic area is restricted to the cross- sectional area of a small rod<br />
piston that operates the flow tube. In addition to dramatically decreasing the<br />
effect of control-fluid hydrostatic pressure, the seal diameters are smaller, so<br />
less force is needed to overcome seal friction. Setting depths in excess of<br />
2000 ft [609 m] true vertical depth (TVD) are possible with a rod-piston valve.<br />
With even smaller rod-piston designs, deep- set valves can be rated to work<br />
at 8000 ft [2438 m] TVD. Several mechanisms have been used to overcome<br />
this depth restriction, including balance lines and gas-spring systems.<br />
Charlie Chong/ Fion Zhang
Rod-piston<br />
SCSSV. In this<br />
valve design,<br />
the hydrauliccontrol<br />
pressure, FH,<br />
acts on a rod<br />
piston,<br />
replacing the<br />
larger, ringshaped<br />
hydraulic area<br />
of a concentricpiston<br />
valve<br />
design. This<br />
much smaller<br />
cross-sectional<br />
area allows<br />
smaller springs,<br />
which is<br />
significant for<br />
valves placed<br />
at great depth.<br />
Charlie Chong/ Fion Zhang
Greater depth can also be achieved by using a gas spring—a nitrogencharged<br />
chamber—as a balancing force that acts in conjunction with the<br />
valve power spring. This charge is preset to reflect the worst-case hydrostatic<br />
pressure in the hydraulic-control line at the valve’s installed depth, thus<br />
following valve-setting depths greater than 12,000 ft [3658 m] TVD. Recently,<br />
three TRCDH safety valves were placed at depths ranging from 10,047 to<br />
10,060 ft [3062 to 3066 m] in the Gulf of Mexico, setting an industry record.<br />
Charlie Chong/ Fion Zhang
Higher well pressures and temperatures also required changes in SCSSV<br />
seal design. Elastomeric sealing materials are susceptible to degradation at<br />
high temperature and in hostile chemical environments. Over time, the<br />
reliability and efficiency of a safety valve using elastomeric sealing may<br />
deteriorate. Camco developed the first safety valve that replaces elastomeric<br />
seals with metal-to-metal sealing systems. In recent years, this technology<br />
has been coupled with metal spring-energized filled Teflon sealing systems to<br />
meet the ever-increasing severity of safety-valve applications. Exploiting<br />
reservoirs in deep water depends on solving technical challenges that only a<br />
few years ago were thought to be insurmountable. Kerr-McGee Oil & Gas<br />
Corp. focuses on developing high-potential core-production areas, such as<br />
the frontier deepwater environment, with a rigorous approach to cost, quality<br />
and technology. Their expertise and rapid response to opportunities and<br />
challenges allow Kerr-McGee to complete developments and achieve early<br />
production within aggressive time frames. The Nansen and Boomvang<br />
developments that came on stream in the first half of 2002 benefited from this<br />
approach (above).<br />
Charlie Chong/ Fion Zhang
Located in the Gulf of Mexico about 135 miles [217 km] south of Galveston,<br />
Texas, USA, the Nansen field lies in 3678 ft [1121 m] of water The field is<br />
developed with a combination of subsea, wet-tree wells and dry-tree wells on<br />
the platform (for more on wet and dry trees, see “High Expectations from<br />
Deepwater Wells,” page 36). At this water depth, a deep-set safetyalve<br />
system with a nitrogen-charged spring is required. With this system, the<br />
safety valve also can be positioned below the critical area in a wellbore where<br />
formation of scale, paraffin or similar wellbore deposits could impact the<br />
operation or reliability of the valve-closure mechanism. The neighboring<br />
Boomvang field was developed in parallel using similar technologies. Kerr-<br />
McGee had a long, successful history using Camco subsurface safety valves,<br />
including the tubing-retrievable TRC-DH series deep-set safety valve, and<br />
experience working with Schlumberger on previous projects. The company<br />
involved Schlumberger engineers in well planning and completion design for<br />
the Nansen project. The TRC-DH safety valve was used for both subsea and<br />
platform wells on the Nansen development.<br />
Charlie Chong/ Fion Zhang
Nansen field, Gulf of Mexico. The Nansen facilities were constructed with a<br />
truss spar, shown in the photograph.<br />
Charlie Chong/ Fion Zhang
Nansen field<br />
Charlie Chong/ Fion Zhang
TRC-DH safety-valve<br />
assembly used in the<br />
Nansen field. Dual<br />
operating pistons<br />
allow operational<br />
redundancy. A gasspring<br />
mechanism is<br />
designed to balance<br />
the weight of the<br />
control-line fluid and<br />
allows use of low<br />
control pressure at<br />
surface. This valve is<br />
designed for deep-set<br />
and high-pressure<br />
applications. The flow<br />
tube rests on the<br />
nose seal when the<br />
flapper is open. This<br />
spring-loaded Teflon<br />
ring prevents debris<br />
and solids from<br />
accumulating in the<br />
flapper and seat<br />
areas.<br />
Charlie Chong/ Fion Zhang
Close cooperation between Kerr-McGee and Schlumberger engineers helped<br />
resolve challenges efficiently without impacting the critical timeline. For<br />
example, long lead times often are required for material sourcing in ambitious<br />
projects, so requirements for special materials or unusual equipment<br />
specifications were identified early. This included obtaining material for<br />
manufacturing valve components, because the relatively large diameter of<br />
safety-valve components requires material in sizes that are not always<br />
commonly available. Kerr-McGee engineers demanded redundant features<br />
and safe operating characteristics. The TRC-DH safety-valve series was<br />
specifically developed for this type of deepwater application. The valve design<br />
incorporates a dual-piston operated control system that provides complete<br />
operating redundancy. The gas-spring system provides substantially lower<br />
control-line pressures at greater setting depths compared with conventional<br />
valve systems. The surface controlline pressure for gas-spring valves in the<br />
Nansen installation is less than 5000 psi [34.5 MPa] at surface, compared<br />
with 10,000 psi [68.9 MPa] that would be required for conventional valve<br />
operating systems.<br />
Charlie Chong/ Fion Zhang
Nansen field wellbore diagram. The<br />
chemical injection mandrels are placed<br />
above the SCSSV in the Nansen field.<br />
Charlie Chong/ Fion Zhang
Using this valve series contributes significantly to reliability of the control and<br />
operating system and reduces hazards associated with extreme-pressure<br />
hydraulic systems. Kerr-McGee selected 31⁄2-in. TRC-DH-10-F tubingretrievable<br />
safety valves for all three of the subsea wells tied to the Nansen<br />
development (above). The nine dry-tree wells used eight 31⁄2-in. valves and<br />
one 41⁄2-in. valve. Three 41⁄2-in. valves of the same specification were<br />
selected for critical subsea completions in the neighboring Boomvang<br />
development. The compact design of the TRC-DH safety valves provides<br />
the principal dimensions of 5.750-in. outside diameter (OD) and 2.750-in.<br />
inside diameter (ID) for the 31⁄2-in. valves, and 7.437-in. OD with 3.688-in. ID<br />
for the 41⁄2-in. valves. Most of the components for this safety valve series are<br />
machined from 13 chrome high strength stainless steel, resulting in a<br />
working pressure of 10,000 psi for both valve sizes. The valve design<br />
incorporates a nose-seal system on the flow tube. This is a spring-loaded<br />
Teflon ring that the bottom of the flow tube rests on when open, thereby<br />
preventing debris and solids from accumulating in the flapper and seat.<br />
Charlie Chong/ Fion Zhang
Work on these subsea wells requires a deepwater drilling rig for well access,<br />
costly and production- delaying process that reinforces the need for reliability<br />
in safety-valve operation. The dual operating systems incorporated in each<br />
valve are independent and fully redundant control systems. This significantly<br />
reduces the risk of having to perform a well intervention or workover operation<br />
should there be a hydraulic-control system problem within the downhole<br />
safety-valve system. A project-management approach to the selection,<br />
manufacture and installation of the safety valve and associated system<br />
components during this multi-well project allowed lessons learned to be<br />
quickly incorporated into the design process for subsequent installations.<br />
For example, during the Nansen project, minor changes in material<br />
specification, product design and installation procedures were implemented<br />
as early experience highlighted opportunities for improvement. Engineering<br />
design changes and amended procedures improved the control-line clamping<br />
system, which simplified safety-valve installation. This level of integration<br />
gives both suppliers and manufacturers a shared responsibility for safety and<br />
environmental issues that are key success indicators for projects such as the<br />
Nansen development.<br />
Charlie Chong/ Fion Zhang
To date, Kerr-McGee and Schlumberger have installed 10 safety valves, all of<br />
which are operating as designed and without failure. The successes and<br />
lessons learned at Nansen and Boomvang fields—including metallurgy,<br />
manufacture, design, operations and personnel aspects for safety-valve<br />
systems—will be carried forward to other deepwater developments in the<br />
Gulf of Mexico.<br />
Future Challenges<br />
The trend toward more complex reservoir development continues to present<br />
challenges for designers of safety-valve systems. Petroleum reserves today<br />
are exploited from deeper water and in harsher producing and operating<br />
conditions than ever before. In these more hostile conditions, material<br />
selection is critical for increasing equipment resistance to corrosion and<br />
material degradation over extended production periods. An essentially<br />
unlimited setting depth could be achieved by developing subsurface safety<br />
valves that incorporate solenoids to activate the valve. This would alleviate<br />
the problem of pressure contributions from the weight of fluid in the control<br />
line or leaks in that line.<br />
Charlie Chong/ Fion Zhang
The need for compact equipment and close engineering tolerances also<br />
presents design and engineering challenges for valves placed in extreme<br />
environments.<br />
Advanced coating materials and application techniques, such as the<br />
ScaleGard coating, have been developed to enhance resistance to surface<br />
deposits on flow wetted and selected valve components. Recent<br />
improvements in chemical-injection technology allow use of ScaleGard<br />
coating within the safety valve to prevent accumulations of production borne<br />
contaminants and help to ensure safety valve system reliability. Larger<br />
safety-valve sizes will soon be needed. In some areas, for example Norway,<br />
plans for mono-bore completions with large-diameter production tubulars<br />
highlight the need for 9 5⁄8-in. safety-valve systems. The forces resulting<br />
from pressure acting on such large component areas are far beyond those of<br />
conventionally sized equipment and present significant additional challenges<br />
to design engineers.<br />
Charlie Chong/ Fion Zhang
The success and reliability of features developed in the past are key to the<br />
development of innovative safety valves for the future. Use of electronic<br />
control equipment in advanced completion systems is increasing (see<br />
“Advances in Well and Reservoir Surveillance,” page 14.) This technology<br />
has proven its reliability and functionality, providing real-time indications of<br />
production behavior. State-of-the-art equipment now delivers these real-time<br />
advantages to downhole safety systems in situations that, above all others,<br />
require rapid response. This critical component of a safety system requires<br />
focus and expertise to continue development and ensure safety and efficient<br />
operation throughout a well’s life. —MA/BA/GMG<br />
Charlie Chong/ Fion Zhang
Charlie Chong/ Fion Zhang<br />
https://www.weatherford.com/en/documents/brochure/products-and-services/drilling/metalskin%C2%AE-monobore-open-hole-liner-system/
PART 2:<br />
• API 14A<br />
Charlie Chong/ Fion Zhang
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Specification for <strong>Subsurface</strong> <strong>Safety</strong><br />
<strong>Valve</strong> Equipment<br />
ANSI/API SPECIFICATION 14A<br />
ELEVENTH EDITION, OCTOBER 2005<br />
EFFECTIVE DATE: MAY 1, 2006<br />
ISO 10432: 2004, (Identical) Petroleum and natural<br />
gas industries—Downhole equipment—<strong>Subsurface</strong><br />
safety valve equipment<br />
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Special Notes<br />
API publications necessarily address problems of a general nature. With respect to particular<br />
circumstances, local, state, and federal laws and regulations should be reviewed.<br />
Neither API nor any of API’s employees, subcontractors, consultants, committees, or other assignees<br />
make any warranty or representation, either express or implied, with respect to the accuracy,<br />
completeness, or usefulness of the information contained herein, or assume any liability or responsibility<br />
for any use, or the results of such use, of any information or process disclosed in this publication. Neither<br />
API nor any of API’s employees, subcontractors, consultants, or other assignees represent that use of<br />
this publication would not infringe upon privately owned rights.<br />
API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to<br />
assure the accuracy and reliability of the data contained in them; however, the Institute makes no<br />
representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims<br />
any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities<br />
having jurisdiction with which this publication may conflict.<br />
API publications are published to facilitate the broad availability of proven, sound engineering and<br />
operating practices. These publications are not intended to obviate the need for applying sound<br />
engineering judgment regarding when and where these publications should be utilized. The formulation<br />
and publication of API publications is not intended in any way to inhibit anyone from using any other<br />
practices.<br />
Any manufacturer marking equipment or materials in conformance with the marking requirements of an<br />
API standard is solely responsible for complying with all the applicable requirements of that standard. API<br />
does not represent, warrant, or guarantee that such products do in fact conform to the applicable API<br />
standard.<br />
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These materials are subject to copyright claims of ISO, ANSI and API.<br />
All rights reserved. No part of this work may be reproduced, stored in a retrieval system, or<br />
transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without<br />
prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L<br />
Street, N.W., Washington, D.C. 20005.<br />
Copyright © 2005 American Petroleum Institute<br />
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API Foreword<br />
This standard shall become effective on the date printed on the cover but may be used voluntarily from<br />
the date of distribution.<br />
This American National Standard is under the jurisdiction of the API SC6 - Subcommittee on <strong>Valve</strong>s &<br />
Wellhead Equipment. This standard is considered identical to the English version of ISO 10432:2004.<br />
ISO 10432 was prepared by Technical Committee ISO/TC 67, Materials, equipment and offshore<br />
structures for petroleum, petrochemical and natural gas industries, SC 4, Drilling and production<br />
equipment which was based on the prior API Specification 14A, Ninth Edition.<br />
The following editorial corrections were incorporated:<br />
• 7.3.1.c.1 Reference should be to Section 4.<br />
• 7.7.4 Replace “…specifies if the optional…” with<br />
“…specifies, the optional…”<br />
• Informative Annex G “API Monogram” was added.<br />
Standards referenced herein may be replaced by other international or national standards that can be<br />
shown to meet or exceed the requirements of the referenced standard. Manufacturers electing to use<br />
another standard in lieu of a referenced standard are responsible for documenting equivalency.<br />
Nothing contained in any API publication is to be construed as granting any right, by implication or<br />
otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters<br />
patent. Neither should anything contained in the publication be construed as insuring anyone against<br />
liability for infringement of letters patent.<br />
This document was produced under API standardization procedures that ensure appropriate notification<br />
and participation in the developmental process and is designated as an API standard. Questions<br />
concerning the interpretation of the content of this publication or comments and questions concerning the<br />
procedures under which this publication was developed should be directed in writing to the Director of<br />
Standards, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for<br />
permission to reproduce or translate all or any part of the material published herein should also be<br />
addressed to the director.<br />
Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A<br />
one-time extension of up to two years may be added to this review cycle. Status of the publication can be<br />
ascertained from the API Standards Department, telephone (202) 682-8000. A catalog of API publications<br />
and materials is published annually and updated quarterly by API, 1220 L Street, N.W., Washington, D.C.<br />
20005.<br />
Suggested revisions are invited and should be submitted to the Standards and Publications Department,<br />
API, 1220 L Street, NW, Washington, DC 20005, standards@api.org.<br />
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API Specification 14A / ISO 10432<br />
Contents<br />
API Foreword .......................................................................................................................................................... ii<br />
Foreword ................................................................................................................................................................ iv<br />
Introduction ............................................................................................................................................................. v<br />
1 Scope .......................................................................................................................................................... 1<br />
2 Normative references ................................................................................................................................ 1<br />
3 Terms and definitions ............................................................................................................................... 3<br />
4 Abbreviated terms ..................................................................................................................................... 7<br />
5 Functional specification ........................................................................................................................... 8<br />
5.1 General ....................................................................................................................................................... 8<br />
5.2 SSSV functional characteristics .............................................................................................................. 8<br />
5.3 Well parameters ......................................................................................................................................... 9<br />
5.4 Operational parameters ............................................................................................................................ 9<br />
5.5 Environmental compatibility .................................................................................................................. 10<br />
5.6 Compatibility with related well equipment ............................................................................................ 10<br />
6 Technical specification ........................................................................................................................... 10<br />
6.1 Technical requirements .......................................................................................................................... 10<br />
6.2 Technical characteristics of SSSV ........................................................................................................ 10<br />
6.3 Design criteria .......................................................................................................................................... 11<br />
6.4 Design verification .................................................................................................................................. 14<br />
6.5 Design validation ..................................................................................................................................... 14<br />
6.6 Design changes ....................................................................................................................................... 15<br />
6.7 Functional test ......................................................................................................................................... 15<br />
7 Supplier/manufacturer requirements .................................................................................................... 16<br />
7.1 General ..................................................................................................................................................... 16<br />
7.2 Raw material ............................................................................................................................................. 16<br />
7.3 Heat-treating-equipment qualification ................................................................................................... 17<br />
7.4 Traceability ............................................................................................................................................... 17<br />
7.5 Components undergoing special processes ........................................................................................ 18<br />
7.6 Quality control ......................................................................................................................................... 18<br />
7.7 SSSV functional testing .......................................................................................................................... 23<br />
7.8 Product identification .............................................................................................................................. 23<br />
7.9 Documentation and data control ........................................................................................................... 24<br />
7.10 Failure reporting and analysis ............................................................................................................... 26<br />
8 Repair/redress .......................................................................................................................................... 26<br />
8.1 Repair ........................................................................................................................................................ 26<br />
8.2 Redress ..................................................................................................................................................... 26<br />
9 Storage and preparation for transport .................................................................................................. 26<br />
Annex A (normative) Test agency requirements ................................................................................................ 27<br />
Annex B (normative) Validation testing requirements ....................................................................................... 30<br />
Annex C (normative) Functional testing requirements ...................................................................................... 40<br />
Annex D (informative) Optional requirement for closure mechanism minimal leakage ................................. 46<br />
Annex E (informative) Operating envelope ......................................................................................................... 47<br />
Annex F (normative) Data requirements, figures/schematics, and tables ....................................................... 49<br />
Annex G (informative) API Monogram ...................................................................................................................77<br />
Bibliography .......................................................................................................................................................... 79<br />
Page<br />
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iii<br />
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ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
Foreword<br />
ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies<br />
(ISO member bodies). The work of preparing International Standards is normally carried out through ISO<br />
technical committees. Each member body interested in a subject for which a technical committee has been<br />
established has the right to be represented on that committee. International organizations, governmental and<br />
non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the<br />
International Electrotechnical Commission (IEC) on all matters of electrotechnical standardization.<br />
International Standards are drafted in accordance with the rules given in the ISO/IEC Directives, Part 2.<br />
The main task of technical committees is to prepare International Standards. Draft International Standards<br />
adopted by the technical committees are circulated to the member bodies for voting. Publication as an<br />
International Standard requires approval by at least 75 % of the member bodies casting a vote.<br />
Attention is drawn to the possibility that some of the elements of this document may be the subject of patent<br />
rights. ISO shall not be held responsible for identifying any or all such patent rights.<br />
ISO 10432 was prepared by Technical Committee ISO/TC 67, Materials, equipment and offshore structures<br />
for petroleum, petrochemical and natural gas industries, Subcommittee SC 4, Drilling and production<br />
equipment.<br />
This third edition cancels and replaces the second edition (ISO 10432:1999), which has been technically<br />
revised.<br />
iv<br />
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iv<br />
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© ISO 2004 – All rights reserved
API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
Introduction<br />
This International Standard has been developed by users/purchasers and suppliers/manufacturers of<br />
subsurface safety valves intended for use in the petroleum and natural gas industry worldwide. This<br />
International Standard is intended to give requirements and information to both parties in the selection,<br />
manufacture, testing and use of subsurface safety valves. Furthermore, this International Standard addresses<br />
the minimum requirements with which the supplier/manufacturer is to comply so as to claim conformity with<br />
this International Standard.<br />
Users of this International Standard should be aware that requirements above those outlined in this<br />
International Standard may be needed for individual applications. This International Standard is not intended<br />
to inhibit a supplier/manufacturer from offering, or the user/purchaser from accepting, alternative equipment or<br />
engineering solutions. This may be particularly applicable where there is innovative or developing technology.<br />
Where an alternative is offered, the supplier/manufacturer should identify any variations from this International<br />
Standard and provide details.<br />
The requirements for lock mandrels and landing nipples previously contained in this International Standard are<br />
now included in ISO 16070.<br />
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v<br />
© ISO 2004 – All rights reserved v<br />
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INTERNATIONAL STANDARD API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
Petroleum and natural gas industries — Downhole<br />
equipment — <strong>Subsurface</strong> safety valve equipment<br />
1 Scope<br />
This International Standard provides the minimum acceptable requirements for subsurface safety valves<br />
(SSSVs). It covers subsurface safety valves including all components that establish tolerances and/or<br />
clearances which may affect performance or interchangeability of the SSSVs. It includes repair operations and<br />
the interface connections to the flow control or other equipment, but does not cover the connections to the well<br />
conduit.<br />
NOTE Limits: The subsurface safety valve is an emergency safety device, and is not intended or designed for<br />
operational activities, such as production/injection reduction, production stop, or as a backflow valve.<br />
Redress activities are beyond the scope of this International Standard, see Clause 8.<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
2 Normative references<br />
The following referenced documents are indispensable for the application of this document. For dated<br />
references, only the edition cited applies. For undated references, the latest edition of the referenced<br />
document (including any amendments) applies.<br />
ISO 48, Rubber, vulcanized or thermoplastic — Determination of hardness (hardness between 10 IRHD and<br />
100 IRHD)<br />
ISO 527-1, Plastics — Determination of tensile properties — Part 1: General principles<br />
ISO 2859-1, Sampling procedures for inspection by attributes — Part 1: Sampling schemes indexed by<br />
acceptance quality limit (AQL) for lot-by-lot inspection<br />
ISO 3601-1, Fluid power systems — O-rings — Part 1: Inside diameters, cross-sections, tolerances and size<br />
identification code<br />
ISO 3601-3, Fluid systems — Sealing devices — O-rings — Part 3: Quality acceptance criteria<br />
ISO 6506-1, Metallic materials — Brinell hardness test — Part 1: Test method<br />
ISO 6507-1, Metallic materials — Vickers hardness test — Part 1: Test method<br />
ISO 6508-1, Metallic materials — Rockwell hardness test — Part 1: Test method (scales A, B, C, D, E, F, G, H,<br />
K, N, T)<br />
ISO 6892, Metallic materials — Tensile testing at ambient temperature<br />
ISO 9000:2000, Quality management systems — Fundamentals and vocabulary<br />
ISO 9712, Non-destructive testing — Qualification and certification of personnel<br />
ISO 10414-1, Petroleum and natural gas industries — Field testing of drilling fluids — Par 1: Water-based<br />
fluids<br />
1<br />
© ISO 2004 – All rights reserved 1<br />
Licensee=Qatar Petroleum/5943408001<br />
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ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
ISO 10417, Petroleum and natural gas industries — <strong>Subsurface</strong> safety valve systems — Design, installation,<br />
operation and redress<br />
ISO 13628-3, Petroleum and natural gas industries — Design and operation of subsea production systems —<br />
Part 3: Through flowline (TFL) systems<br />
ISO 13665, Seamless and welded steel tubes for pressure purposes — Magnetic particle inspection of the<br />
tube body for the detection of surface imperfections<br />
ISO 15156 (all parts), Petroleum and natural gas industries — Materials for use in H 2 S-containing<br />
environments in oil and gas production<br />
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ISO 16070, Petroleum and natural gas industries — Downhole equipment — Lock mandrels and landing<br />
nipples<br />
ISO/IEC 17025, General requirements for the competence of testing and calibration laboratories<br />
ANSI/NCSL Z540-1:1994, General requirements for calibration laboratories and measuring and test<br />
equipment 1)<br />
API Manual of Petroleum Measurement Standards, Chapter 10.4, Determination of sediment and water in<br />
crude oil by the centrifuge method (field procedure) 2)<br />
API Spec 5B, Threading, gauging, and thread inspection of casing, tubing, and line pipe threads<br />
API Spec 14A, Specification for subsurface safety valve equipment<br />
ASME Boiler and Pressure Vessel Code, Section II, Materials specification 3)<br />
ASME Boiler and Pressure Vessel Code, Section V, Nondestructive examination<br />
ASME Boiler and Pressure Vessel Code, Section VIII:2001, Pressure vessels<br />
ASME Boiler and Pressure Vessel Code, Section IX, Welding and brazing qualifications<br />
ASTM A 388/A 388M, Standard practice for ultrasonic examination of heavy steel forgings 4)<br />
ASTM A 609/A 609M, Standard practice for castings, carbon, low-alloy, and martensitic stainless steel,<br />
ultrasonic examination thereof<br />
ASTM D 395, Standard test methods for rubber property — Compression set<br />
ASTM D 412, Standard test methods for vulcanized rubber and thermoplastic elastomers — Tension<br />
ASTM D 1414, Standard test methods for rubber O-rings<br />
ASTM D 2240, Standard test methods for rubber propert — Durometer hardness<br />
ASTM E 94, Standard guide for radiographic examination<br />
ASTM E 140, Standard hardness conversion tables for metals. (Relationship among Brinell hardness, Vickers<br />
hardness, Rockwell hardness, superficial hardness, Knoop hardness, and scleroscope hardness)<br />
1) NCSL International, 2995 Wilderness Place, Suite 107, Boulder, Colorado 80301-5404, USA.<br />
2) American Petroleum Institute, 1220 L Street NW, Washington, DC 20005-4070, USA.<br />
3) American Society of Mechanical Engineers, Three Park Avenue, New York, NY 10016-5990, USA.<br />
4) American Society for Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, PA 19428-2959, USA.<br />
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ASTM E 165, Standard test method for liquid penetrant examination<br />
ASTM E 186, Standard reference radiographs for heavy-walled [2 to 4 1/2-in. (51 to 114-mm)] steel castings<br />
ASTM E 280, Standard reference radiographs for heavy-walled [4 1/2 to 12-in. (114 to 305-mm)] steel<br />
castings<br />
ASTM E 428, Standard practice for fabrication and control of steel reference blocks used in ultrasonic<br />
inspection<br />
ASTM E 446, Standard reference radiographs for steel castings up to 2 in. (51 mm) in thickness<br />
ASTM E 709, Standard guide for magnetic particle examination<br />
BS 2M 54:1991, Temperature control in the heat treatment of metals 5)<br />
SAE-AMS-H-6875:1998, Heat treatment of steel raw materials 6)<br />
3 Terms and definitions<br />
For the purposes of this document, the terms and definitions given in ISO 9000:2000 and the following apply.<br />
3.1<br />
bean<br />
orifice<br />
designed restriction causing the pressure drop in velocity-type SSCSVs<br />
3.2<br />
design acceptance criteria<br />
defined limits placed on characteristics of materials, products, or services established by the organization,<br />
customer, and/or applicable specifications to achieve conformity to the product design<br />
[ISO/TS 29001:2003]<br />
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3.3<br />
design validation<br />
process of proving a design by testing to demonstrate conformity of the product to design requirements<br />
[ISO/TS 29001:2003]<br />
3.4<br />
design verification<br />
process of examining the result of a given design or development activity to determine conformity with<br />
specified requirements<br />
[ISO/TS 29001:2003]<br />
3.5<br />
end connection<br />
thread or other mechanism providing equipment-to-tubular interface<br />
3.6<br />
environment<br />
set of conditions to which the product is exposed<br />
5) BSI, Customer Services, 389 Chiswick High Road, London W4 4AL, UK.<br />
6) SAE International, 400 Commonwealth Drive, Warrendale, PA 15096-0001, USA.<br />
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3.7<br />
failure<br />
any equipment condition that prevents it from performing to the requirements of the functional specification<br />
3.8<br />
fit<br />
geometric relationship between parts<br />
NOTE<br />
This includes the tolerance criteria used during the design of a part and its mating parts, including seals.<br />
3.9<br />
form<br />
essential shape of a product including all its component parts<br />
3.10<br />
function<br />
operation of a product during service<br />
3.11<br />
functional test<br />
test performed to confirm proper operation of equipment<br />
3.12<br />
heat treatment<br />
heat treating<br />
alternate steps of controlled heating and cooling of materials for the purpose of changing mechanical<br />
properties<br />
3.13<br />
interchangeable<br />
conforming in every detail, within specified tolerances, to both fit and function of a safe design but not<br />
necessarily to the form<br />
3.14<br />
manufacturer<br />
principal agent in the design, fabrication and furnishing of equipment, who chooses to comply with this<br />
International Standard<br />
3.15<br />
manufacturing<br />
process and action performed by an equipment supplier/manufacturer that are necessary to provide finished<br />
component(s), assembly(ies) and related documentation, that fulfil the requests of the user/purchaser and<br />
meet the standards of the supplier/manufacturer<br />
NOTE Manufacturing begins when the supplier/manufacturer receives the order and is completed at the moment the<br />
component(s), assembly(ies) and related documentation are surrendered to a transportation provider.<br />
[ISO 16070]<br />
3.16<br />
mass loss corrosion<br />
weight loss corrosion (deprecated term)<br />
loss of metal in areas exposed to fluids which contain water or brine and carbon dioxide (CO 2 ), oxygen (O 2 ) or<br />
other corrosive agents<br />
NOTE<br />
The term “weight” is commonly incorrectly used to mean mass, but this practice is deprecated.<br />
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3.17<br />
model<br />
SSSV equipment with unique components and operating characteristics which differentiate it from other SSSV<br />
equipment of the same type<br />
NOTE<br />
The same model can have any of a variety of end connections.<br />
3.18<br />
operating manual<br />
publication issued by the manufacturer which contains detailed data and instructions related to the design,<br />
installation, operation and maintenance of equipment<br />
3.19<br />
profile<br />
feature that is designed for the reception of a locking mechanism<br />
3.20<br />
proof test<br />
test specified by the manufacturer which is performed to verify that the SSSV meets those requirements of the<br />
technical specification which are relevant to the validation testing performance<br />
3.21<br />
qualified part<br />
part manufactured under a recognized quality assurance programme and, in the case of replacement,<br />
produced to meet or exceed the performance of the original part produced by the original equipment<br />
manufacturer (OEM)<br />
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NOTE<br />
ISO 9001 is an example of a recognized quality assurance programme.<br />
[ISO 10417]<br />
3.22<br />
redress<br />
any activity involving the replacement of qualified parts<br />
cf. repair (3.23)<br />
NOTE<br />
See Clause 8 for more information.<br />
3.23<br />
repair<br />
any activity beyond the scope of redress that includes disassembly, re-assembly, and testing with or without<br />
the replacement of parts and may include machining, welding, heat treating or other manufacturing<br />
operations, that restores the equipment to its original performance<br />
cf. redress (3.22)<br />
[ISO 10417]<br />
NOTE<br />
See Clause 8 for more information.<br />
3.24<br />
sealing device<br />
device preventing contact of liquid and/or gas across the interface between the lock mandrel and the landing<br />
nipple<br />
3.25<br />
size<br />
relevant dimensional characteristics of the equipment as defined by the manufacturer<br />
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3.26<br />
sour service<br />
exposure to oilfield environments that contain H 2 S and can cause cracking of materials by the mechanisms<br />
addressed in ISO 15156<br />
NOTE Adapted from ISO 15156-1:2001.<br />
3.27<br />
special feature<br />
specific component or sub-assembly that provides a functional capability that is not validated during the<br />
validation test conducted in accordance with 6.5<br />
3.28<br />
subsurface safety valve<br />
SSSV<br />
device whose design function is to prevent uncontrolled well flow when closed<br />
NOTE SSSVs can be installed and retrieved by wireline or pump-down methods (wireline-retrievable) or be an integral<br />
part of the tubing string (tubing-retrievable).<br />
3.29<br />
subsurface safety valve equipment<br />
SSSV equipment<br />
subsurface safety valve, and all components that establish tolerances and/or clearances which can affect its<br />
performance or interchangeability<br />
3.30<br />
stress corrosion cracking<br />
SCC<br />
cracking of metal involving anodic processes of localized corrosion and tensile stress (residual and/or applied)<br />
in the presence of water and H 2 S<br />
NOTE Chlorides and/or oxidants and elevated temperature can increase the susceptibility of metals to this<br />
mechanism of attack.<br />
[ISO 15156-1]<br />
3.31<br />
stress cracking<br />
stress corrosion cracking, or sulfide stress cracking, or both<br />
NOTE Adapted from NACE MR0175: Jan 2003.<br />
3.32<br />
stress relief<br />
controlled heating of material to a predetermined temperature for the purpose of reducing any residual<br />
stresses<br />
3.33<br />
sulfide stress cracking<br />
SSC<br />
cracking of metal involving corrosion and tensile stress (residual and/or applied) in the presence of water and<br />
H 2 S<br />
NOTE SSC is a form of hydrogen stress cracking (HSC) and involves embrittlement of the metal by atomic hydrogen<br />
that is produced by acid corrosion on the metal surface. Hydrogen uptake is promoted in the presence of sulfides. The<br />
atomic hydrogen can diffuse into the metal, reduce ductility and increase susceptibility to cracking. High strength metallic<br />
materials and hard weld zones are prone to SSC.<br />
[ISO 15156-1]<br />
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3.34<br />
test agency<br />
organization which provides a test facility and administers a test program that meets the validation test<br />
requirements of this International Standard<br />
NOTE<br />
See Annex A for test agency requirements.<br />
3.35<br />
test pressure<br />
pressure at which the equipment is tested based upon all relevant design criteria<br />
3.36<br />
test section<br />
test apparatus which contains the SSSV and provides for connection to a test facility's validation test<br />
apparatus<br />
3.37<br />
type<br />
SSSV equipment with unique characteristics which differentiate it from other functionally similar SSSV<br />
equipment<br />
EXAMPLES<br />
SCSSV, velocity-type SSCSV and low-tubing-pressure-type SSCSV are types of SSSV.<br />
3.38<br />
validation test<br />
test performed to qualify a particular size, type and model of equipment for a specific class of service<br />
NOTE<br />
See Annex B for details.<br />
3.39<br />
working pressure<br />
SSSV internal pressure rating, including the differential rating with the valve closed<br />
4 Abbreviated terms<br />
AQL<br />
NDE<br />
TFL<br />
SCSSV<br />
SSCSV<br />
SSSV<br />
TRSV<br />
WRSV<br />
acceptance quality limit<br />
non-destructive examination<br />
through flowline<br />
surface-controlled subsurface safety valve<br />
subsurface controlled subsurface safety valve<br />
subsurface safety valve<br />
tubing-retrievable safety valve<br />
wireline-retrievable safety valve<br />
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ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
5 Functional specification<br />
5.1 General<br />
5.1.1 Functional requirements<br />
The user/purchaser shall prepare a functional specification for ordering products which conform with this<br />
International Standard and specify the following requirements and operating conditions, as appropriate, and/or<br />
identify the supplier's/manufacturer's specific product. These requirements and operating conditions may be<br />
conveyed by means of a dimensional drawing, data sheet or other suitable documentation.<br />
5.1.2 Classes of service<br />
SSSV equipment manufactured in accordance with this International Standard shall conform to one or more of<br />
the following classes of service. The user/purchaser shall specify the class(s), as applicable.<br />
⎯<br />
⎯<br />
⎯<br />
Class 1: standard service. This class of SSSV equipment is intended for use in wells which are not<br />
expected to exhibit the detrimental effects defined by Classes 2, 3, or 4.<br />
Class 2: sandy service. This class of SSSV equipment is intended for use in wells where particulates<br />
such as sand could be expected to cause SSSV equipment failure.<br />
Class 3: stress cracking service. This class of SSSV equipment is intended for use in wells where<br />
water containing corrosive agents can cause stress cracking. Class 3 equipment shall meet the<br />
requirements for Class 1 or Class 2 service and be manufactured from metallic materials that are<br />
demonstrated as resistant to sulfide stress cracking and stress corrosion cracking.<br />
NOTE<br />
⎯<br />
The supplier/manufacturer shall ensure that the metallic materials used in Class 3 equipment meet the<br />
metallurgical requirements of ISO 15156 (all parts) for sour service and/or shall be suitable for service in<br />
non-sour-containing environments where stress corrosion cracking can occur.<br />
The user/purchaser shall ensure that the specific metallic materials contained within Class 3 equipment<br />
are suitable for the intended application.<br />
Within Class 3, there are two sub-classes, as follows:<br />
1) 3S for sulfide stress cracking service and stress corrosion cracking service in which chlorides are<br />
present in a sour environment. Metallic materials suitable for a 3S environment shall be in<br />
accordance with ISO 15156 (all parts).<br />
2) 3C for stress corrosion cracking service in a non-sour environment. Metallic materials suitable for<br />
Class 3C non-sour service are dependent on specific well conditions; no national or international<br />
standards exist for the application of metallic materials for this class of service.<br />
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For the purposes of these provisions, NACE MR0175/ISO 15156-1-2-3, is equivalent to ISO 15156 (all parts).<br />
Class 4: mass loss corrosion service (see 3.16). This class of SSSV equipment is intended for use in<br />
wells where corrosive agents could be expected to cause mass loss corrosion. Class 4 equipment shall<br />
meet the requirements for Class 1 or Class 2 and be manufactured from materials which are resistant to<br />
mass loss corrosion. Metallic materials suitable for Class 4 service are dependent on specific well<br />
conditions; no national or international standards exist for the application of metallic materials for this<br />
class of service.<br />
5.2 SSSV functional characteristics<br />
The SSSV functional characteristics should include but are not limited to the following:<br />
a) type of SSSV control (surface-controlled, subsurface-controlled);<br />
b) type of SSSV retrieval (tubing-retrievable, WL-retrievable, coil-tubing-retrievable, TFL-retrievable, etc.);<br />
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c) type of SSSV closing mechanism (ball, flapper, etc.);<br />
d) requirement for internal self-equalizing capability;<br />
e) requirement, if any, for holding the SCSSV open without the use of the primary operating source<br />
(temporary or permanent lock-open system);<br />
f) requirement, if any, for providing control fluid communication from the SCSSV to any other subsurface<br />
device (e.g. a through-tubing retrievable secondary valve);<br />
g) requirement, if any, for providing pump-through capability;<br />
h) requirement, if any, for a redundant/independent back-up operating system;<br />
i) requirements, if any, for minimal leakage (in accordance with 6.7.2) during functional testing.<br />
5.3 Well parameters<br />
The following characteristics shall be specified as applicable:<br />
a) well location (land, platform, subsea);<br />
b) size, mass, grade and material of the casing and tubing;<br />
c) setting depth (maximum required for application) and control system parameters (control fluid<br />
type/properties, supply pressure, supply line(s) and connection rating(s), etc.);<br />
d) casing and/or tubing architecture, trajectory, deviations, maximum dog leg severity;<br />
e) restrictions through which the SSSV shall pass and restrictions/profiles through which the SSSV service<br />
tools/accessories shall pass;<br />
f) requirement, if any, for passage of additional lines (electrical, hydraulic), between the valve OD and the<br />
casing ID, if applicable.<br />
5.4 Operational parameters<br />
5.4.1 SSSVs<br />
The following operational parameters, as applicable, shall be specified for the SSSV:<br />
a) rated working pressure;<br />
b) rated temperature range;<br />
c) if applicable, maximum allowable pressure drop at maximum flow rate through SSSV;<br />
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d) loading conditions, including combined loading (pressures, tension/compression, torque, bending) and<br />
the corresponding temperature extremes anticipated to be applied to the valve;<br />
e) well stimulation operations, including its parameters, such as acidizing (give the composition of the acid),<br />
the pressure, the temperature, the acid flow rate and the exposure time, as well as any other chemicals<br />
used during the stimulation;<br />
f) sand consolidation and fracturing operations, including sand/proppant description, fluid flow rate,<br />
proppant/fluid ratio or sand/fluid ratio, chemical composition, pressure and temperature;<br />
g) well-servicing activities through the safety valve: size, type and configuration of other devices to be run<br />
through the valve, if applicable.<br />
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5.4.2 SSCSVs<br />
The conditions under which the SSCSV will operate (flow conditions) and the conditions under which the valve<br />
should close (see ISO 10417) shall be specified, such as<br />
a) at valve setting depth, the minimum, maximum and normal values of the production/injection pressures<br />
and temperatures at the anticipated flow rates;<br />
b) composition of the production fluid (gas/oil/water) and density of each component.<br />
5.5 Environmental compatibility<br />
The following shall be identified for the SSSV to ensure environmental compatibility:<br />
a) production/injection/annulus fluid chemical and physical composition, including solids (sand production,<br />
scale, etc.), to which the SSSV is exposed during its full life cycle;<br />
b) in cases where the user/purchaser has access to corrosion-property historical data and/or research which<br />
is applicable to the functional specification, the user/purchaser should state to the manufacturer which<br />
material(s) has the ability to perform as required within a similar corrosion environment.<br />
5.6 Compatibility with related well equipment<br />
The following information, as applicable, shall additionally be specified to ensure the compatibility of the SSSV<br />
with the related well equipment:<br />
a) SSSV size, type, material, the configuration of the interface connections (these connections are not<br />
included in the evaluation of combined loading);<br />
b) internal receptacle profile(s), sealing bore dimension(s), outside diameter, inside diameter and their<br />
respective locations;<br />
c) requirement(s) for passage of conduits (electrical/hydraulic) between valve OD and casing ID.<br />
6 Technical specification<br />
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6.1 Technical requirements<br />
The supplier/manufacturer shall prepare and provide to the user/purchaser the technical specification that<br />
responds to the requirements defined in the functional specification.<br />
6.2 Technical characteristics of SSSV<br />
The following criteria shall be met:<br />
a) the SSSV shall be located and/or seal at the specified location and remain so until intentional intervention<br />
defines otherwise;<br />
b) while installed, the SSSV shall perform in accordance with the functional specification;<br />
c) where applicable, the SSSV shall not compromise well-intervention operations as specified in 5.4;<br />
d) while in service, the SSSV shall meet the requirements of the functional specification.<br />
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6.3 Design criteria<br />
6.3.1 General<br />
SSSV design shall permit prediction and repeatability of rates, pressures or other conditions required for<br />
closure.<br />
6.3.2 Design requirements<br />
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6.3.2.1 Documentation of designs shall include methods, assumptions, calculations and design<br />
requirements. Design requirements shall include but not be limited to those criteria for size, test, working and<br />
operating pressures, materials, environment (temperature limits, service class, chemicals) and other pertinent<br />
requirements upon which the design is based. Design documentation shall be reviewed and verified by a<br />
qualified individual other than the individual who created the original design.<br />
6.3.2.2 SSSV equipment conforming to this International Standard shall be manufactured to drawings<br />
and specifications that are substantially the same as those of the size, type, and model SSSV equipment that<br />
has passed the validation test.<br />
6.3.2.3 The manufacturer shall establish verified internal yield pressure, collapse pressure and minimum<br />
tensile strength, temperature limits, and rated working pressure, excluding end connections. The manufacturer<br />
shall identify the critically stressed components of the product and the mode of stress. The manufacturer shall<br />
calculate the critical stress level in the identified component(s) based upon the maximum loads in the design<br />
input requirements. The minimum acceptable material condition and minimum acceptable material yield shall<br />
be used in the calculations and the calculations shall include consideration of temperature limit effects and<br />
thermal cycles. Metal mechanical properties de-rating shall be in accordance with ASME Boiler and Pressure<br />
Vessel Code, Section II, Part D.<br />
The design shall take into account the effects of pressure containment and pressure-induced loads.<br />
Specialized conditions shall also be considered such as pressure testing with temporary test plugs.<br />
6.3.2.4 Component and subassembly identification and interchangeability shall be required within each<br />
manufacturer's service class, size, type and model, including working pressure rating of SSSV equipment.<br />
Additive dimensional tolerances of components shall be such that proper operation of the SSSV equipment is<br />
assured. This requirement applies to manufacturer-assembled equipment and to replacement components or<br />
sub-assemblies.<br />
6.3.2.5 TRSV profiles that interface with locks and sealing devices covered by ISO 16070 shall comply<br />
with the requirements of that International Standard.<br />
6.3.3 Working pressure de-rating<br />
6.3.3.1 Working pressure de-rating of SSSVs of the same nominal size, type and model is permitted by<br />
reference to a successfully validation-tested product (base design) when the requirements of this subclause<br />
and this International Standard are satisfied. The rated working pressure of a de-rated design may be less<br />
than that of the base design by a maximum of 50 %.<br />
6.3.3.2 In establishing a de-rated design, the manufacturer shall identify the critically stressed<br />
components of the base design, establish the maximum stress factors within those components at the<br />
maximum rated conditions and the specific mode of that stress. All design considerations and stress factors<br />
applied to the base design and its components shall be applied to the de-rated design evaluation.<br />
The manufacturer shall establish the maximum stress factors in the equivalent components within the de-rated<br />
design. The minimum acceptable material condition, minimum acceptable material yield strengths, and<br />
maximum and minimum temperature effects on material properties shall be used.<br />
6.3.3.3 Evaluation of the de-rated design shall include comparison of the calculated maximum stress<br />
factors stated as a percentage of material yields of the components of the base design; these shall not exceed<br />
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the maximum stress factors of the components of the base design. The mode of stress and same method of<br />
calculation(s)/evaluation(s) shall be applied to the identified components of both product designs.<br />
Adjustments to material thickness or yield strengths shall not negatively impact maximum stress factors. The<br />
de-rated product shall be evaluated by the manufacturer to ensure that it will meet the requirements of the<br />
validation test.<br />
6.3.3.4 Each de-rated product requires evaluation, justification and design documentation of the changes.<br />
Documentation shall be included in the product's design records.<br />
6.3.4 Materials<br />
6.3.4.1 General<br />
a) Materials, and/or the service, shall be stated by the supplier/manufacturer and shall be suitable for the<br />
class of service and the environment specified in the functional specification. The manufacturer shall have<br />
written specifications for all materials. All materials used shall comply with the manufacturer's written<br />
specifications.<br />
b) The user/purchaser may specify materials for the specific corrosion environment in the functional<br />
specification. Should the manufacturer propose to use another material, the manufacturer shall state that<br />
this material has performance characteristics suitable for all parameters specified in the well and<br />
production/injection parameters. This applies to metallic and non-metallic components.<br />
c) Material substitutions in qualified SSSV equipment are allowed without validation testing provided that the<br />
manufacturer's selection criteria are documented and meet all other requirements of this International<br />
Standard.<br />
6.3.4.2 Metals<br />
6.3.4.2.1 The manufacturer's specifications shall define the following:<br />
a) chemical-composition limits;<br />
b) heat treatment conditions;<br />
c) mechanical-property limits:<br />
1) tensile strength,<br />
2) yield strength,<br />
3) elongation,<br />
4) hardness.<br />
6.3.4.2.2 The mechanical properties specified in 6.3.4.2.1 c) for traceable metal components shall be<br />
verified by tests conducted on a material sample produced from the same heat of material. The material<br />
sample shall experience the same heat treatment process as the component it qualifies. Material<br />
subsequently heat-treated from the same heat of material shall be hardness-tested after processing to confirm<br />
compliance with the hardness requirements of the manufacturer's specifications. The hardness results shall<br />
verify through documented correlation that the mechanical properties of the material tested meet the<br />
properties specified in 6.3.4.2.1.c). The heat treatment process parameters shall be defined in the heat<br />
treatment procedure. Hardness testing is the only mechanical-property test required after stress relieving.<br />
Material test reports provided by the material supplier or the manufacturer are acceptable documentation.<br />
6.3.4.2.3 Each welded component shall be stress-relieved as specified in the manufacturer's written<br />
specifications and, where applicable, in accordance with paragraphs UCS-56 and UHA-32, Section VIII,<br />
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ISO 10432:2004(E)<br />
Division 1, Subsection C, ASME Boiler and Pressure Vessel Code. In addition, carbon and low-alloy steel<br />
weldments on Class 3S SSSV equipment shall be stress-relieved in accordance with ISO 15156 (all parts).<br />
NOTE<br />
For the purposes of these provisions, NACE MR0175/ISO 15156-1-2-3, is equivalent to ISO 15156 (all parts).<br />
6.3.4.3 Non-metals<br />
6.3.4.3.1 The manufacturer shall have documented procedures, including acceptance criteria, for<br />
evaluations or testing of sealing materials or other non-metals to the limits for which the equipment is rated.<br />
6.3.4.3.2 Evaluations (or tests) shall verify the material used is suitable for use in the specific configuration,<br />
environment and application. These evaluations shall include the combination of: pressure, temperature,<br />
geometric seal design and its application, and the fluids compatible with the intended application.<br />
6.3.4.3.3 Sealing devices and materials previously qualified in accordance with prior editions of ISO 10432<br />
or API Spec 14A for the relevant range of application shall be considered as meeting the design validation<br />
requirements of this International Standard.<br />
6.3.4.3.4 The manufacturer's written specifications for non-metallic compounds shall include handling,<br />
storage and labelling requirements, including the cure date, batch number, compound identification and shelf<br />
life appropriate to each compound and shall define those characteristics critical to the performance of the<br />
material, such as the following:<br />
a) compound type;<br />
b) mechanical properties, as a minimum:<br />
1) tensile strength (at break),<br />
2) elongation (at break),<br />
3) tensile modulus (at 50 % or 100 %, as applicable);<br />
c) compression set;<br />
d) durometer hardness.<br />
6.3.5 Performance data<br />
6.3.5.1 Performance rating-SCSSV<br />
The supplier/manufacturer shall state the pressure, temperature and axial load rating, as applicable for the<br />
specific product. This information may be provided in an operating performance envelope; an example is<br />
given in Annex E.<br />
6.3.5.2 Performance rating-SSCSV<br />
The supplier/manufacturer shall provide the following information, as applicable, to establish the closing<br />
conditions for the specific product:<br />
a) orifice size;<br />
b) setting spring;<br />
c) number of spacers to be used;<br />
d) pressure charge.<br />
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6.3.6 TFL equipment<br />
For additional requirements for these products in TFL applications, see ISO 13628-3.<br />
6.4 Design verification<br />
Design verification shall be performed to ensure that each SSSV design meets the supplier's/manufacturer's<br />
technical specifications. Design verification includes activities such as design reviews, design calculations,<br />
physical tests, comparison with similar designs and historical records of defined operating conditions.<br />
6.5 Design validation<br />
6.5.1 General<br />
The SSSVs produced in accordance with this International Standard shall pass the validation test required by<br />
this subclause.<br />
a) SSSVs shall pass the applicable validation test specified in Annex B and shall be performed by a test<br />
agency.<br />
b) Seals shall meet the requirements of 6.3.4.3.<br />
The validation testing requirements in this International Standard are not represented as well conditions.<br />
The objectives of the validation testing requirements of this subclause are to qualify SSSV equipment for<br />
specific classes of service, either Class 1 or Class 2. SSSV equipment furnished to this International Standard<br />
requires validation testing to qualify each size, type and model of SSSV. Qualification for Class 2 service shall<br />
include testing for Class 1 service. An SSSV passing the Class 1 portion, but failing the Class 2 portion of the<br />
combined test, shall be qualified for Class 1 service only.<br />
Successful completion of the validation testing process shall qualify SSSVs of the same size, type and model<br />
as the tested SSSV.<br />
Substantive changes to the validation test (specified herein) shall require requalification of a previously<br />
qualified SSSV within three years of the effective date of the change.<br />
With mutual consent between the test agency and the manufacturer, higher flow rates than those stipulated in<br />
Annex B may be applied and used for all flow tests.<br />
6.5.2 Manufacturer requirements<br />
a) The SSSV shall be proof tested to ensure the valve meets the requirements of the technical specification<br />
with the manufacturer's specified safety factors. The manufacturer shall provide the test agency with an<br />
SSSV of most recent manufacture, one operating manual, records of proof testing, and associated<br />
documentation for each size, type and model for the class of service and working pressure desired in the<br />
validation test.<br />
b) The manufacturer shall maintain a validation test file on each validation test including any retests that<br />
may have been required to qualify SSSV equipment and seals. This file shall be retained by the<br />
manufacturer for a period of ten years after such SSSV equipment and seals are discontinued from the<br />
manufacturer's product line.<br />
c) The manufacturer shall furnish any equipment not normally furnished by the test agency to accommodate<br />
installation of a particular SSSV in the test facility or to accomplish the validation test.<br />
d) The manufacturer shall submit a validation test application for each SSSV to be validation tested to the<br />
test agency that shall contain the manufacturer's test application as required in A.1.<br />
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e) In the event that a particular SSSV has design or operational features which are incompatible with the<br />
test facility and test procedures required by this International Standard, the manufacturer shall advise the<br />
test agency as to the nature of the incompatibility and shall request and fully describe on the test<br />
application, or attachments thereto, any equipment or procedures required to test the SSSV.<br />
Responsibility for furnishing, installing and testing this equipment shall be by agreement between the test<br />
agency and the manufacturer. The manufacturer shall be responsible for assuring that such equipment or<br />
procedures are not less stringent than this International Standard.<br />
f) In the case of validation test non-conformance, the manufacturer shall be responsible for determining the<br />
cause of the non-conformance. The test agency shall cooperate with the manufacturer to determine<br />
whether the non-conformance was product or test agency related. If the nonconformance is determined to<br />
be valve-related, the nonconformance becomes a test failure; if the nonconformance is determined to be<br />
test agency related, the manufacturer and test agency shall determine a course of action on the validation<br />
test process for the specific valve that is not less stringent than the validation testing requirements of this<br />
International Standard. The test agency shall document the testing non-conformance on the test data<br />
forms.<br />
g) If a particular size, type and model of SSSV fails the validation test, that SSSV and any other SSSV of the<br />
same basic design and materials of construction shall not be submitted for retest until the manufacturer<br />
has determined and documented the justification for retest. The manufacturer shall conduct this analysis<br />
and document the results, including any corrective action taken. Such information need not be submitted<br />
to the test agency, but shall be placed in the manufacturer's test file for that SSSV before the SSSV is<br />
submitted for retest.<br />
h) Pre-test and post-test dimensional verification of functionally critical dimensions defined by the<br />
manufacturer shall be conducted and documented by the manufacturer. Dimensions shall be within<br />
established criteria.<br />
6.5.3 Test agency requirements<br />
Test agency requirements are provided in Annex A.<br />
6.5.4 Special feature validation<br />
The manufacturer shall identify, in design documentation, all special features included in the product design<br />
that are not validated by design validation testing per this International Standard. Special features shall be<br />
validated by test to their rated limits. Special feature validation testing may be performed by the manufacturer.<br />
The manufacturer shall identify those special features that shall be included in the functional testing.<br />
The manufacturer's design validation documentation shall include the design requirements, test procedures<br />
and test results of special features.<br />
6.6 Design changes<br />
Changes to the design acceptance criteria of the SSSV design which may affect validation test performance<br />
or interchangeability shall require requalification of the SSSV design. Seals that meet the requirements of<br />
6.3.4.3 shall be considered interchangeable among the SSSV equipment of any one manufacturer.<br />
The manufacturer/supplier shall, as a minimum, consider the following when making design changes: stress<br />
levels of the modified or changed components; material changes; and functional changes. All design changes<br />
and modifications shall be identified, documented, reviewed and approved before their implementation.<br />
Design changes and changes to design documents shall require the same control features as the design<br />
which has passed the applicable validation test requirements of this International Standard.<br />
6.7 Functional test<br />
6.7.1 Each SSSV shall be tested in accordance with Annex C.<br />
6.7.2 Optional minimal leakage requirements are given in Annex D.<br />
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7 Supplier/manufacturer requirements<br />
7.1 General<br />
Clause 7 contains the detailed requirements to verify that each product manufactured under this International<br />
Standard meets the requirements of the functional and technical specifications.<br />
7.2 Raw material<br />
7.2.1 Certification<br />
Raw material used in the manufacture of components shall require the following:<br />
a) certificate of conformance stating that the raw material meets the manufacturer's documented<br />
specifications;<br />
b) material test report so that the manufacturer can verify that the raw material meets their documented<br />
specifications.<br />
7.2.2 Mechanical and physical properties<br />
7.2.2.1 Metals<br />
Tensile testing shall be in accordance with ISO 6892 for the metallic materials used for traceable components.<br />
Hardness testing shall be in accordance with ISO 6506-1 or ISO 6508-1; ISO 6507-1 may be used if<br />
ISO 6506-1 or ISO 6508-1 cannot be applied due to size, accessibility, or other limitations. Hardness<br />
conversion to other measurement units shall be in accordance with ASTM E 140, with the exceptions noted in<br />
ISO 15156 (all parts) for materials that are intended for use in wells where corrosive agents can possibly be<br />
expected to cause stress-corrosion cracking.<br />
NOTE<br />
For the purposes of these provisions, NACE MR0175/ISO 15156-1-2-3 is equivalent to ISO 15156 (all parts).<br />
7.2.2.2 Non-metals<br />
Non-metals shall be tested to determine their mechanical properties as follows:<br />
a) tensile, elongation, modulus:<br />
1) O-rings in accordance with ASTM D 1414,<br />
2) other elastomers in accordance with ASTM D 412 (alternative ISO or ASTM methods may be used,<br />
where applicable),<br />
3) non-elastomers in accordance with ISO 527-1;<br />
NOTE For the purposes of these provisions, ASTM D 638 is equivalent to ISO 527-1.<br />
b) compression set (homogeneous elastomeric compounds only):<br />
1) O-rings in accordance with ASTM D 1414,<br />
2) all others in accordance with ASTM D 395;<br />
c) durometer hardness:<br />
1) O-rings in accordance with ISO 48 or ASTM D 2240 with Shore M,<br />
NOTE For the purposes of these provisions, ASTM D 1415 is equivalent to ISO 48.<br />
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2) other elastomers in accordance with ASTM D 2240 (plastics and other materials may be tested using<br />
the Rockwell method, where applicable).<br />
7.3 Heat-treating-equipment qualification<br />
7.3.1 Furnace calibration<br />
Furnaces for heat treatment of production parts shall require the following.<br />
a) Heat treatment of production parts shall be performed with heat treating equipment that has been<br />
calibrated and surveyed.<br />
b) Each furnace shall have been surveyed within one year prior to heat treating operations. When a furnace<br />
is repaired or rebuilt, a new inspection shall be required before heat treating.<br />
c) Batch-type and continuous-type heat treating furnaces shall be calibrated in accordance with one of the<br />
following procedures:<br />
1) procedures specified in SAE-AMS-H-6875:1998, Section 4;<br />
2) procedures specified in BS 2M 54:1991, Section 7;<br />
3) manufacturer's written specifications including acceptance criteria which are not less stringent than<br />
the procedures identified above.<br />
7.3.2 Furnace instrumentation<br />
The requirements for furnace instrumentation are as follows.<br />
a) Automatic controlling and recording instruments shall be used.<br />
b) Thermocouples shall be located in the furnace working zone(s) and protected from furnace atmospheres.<br />
c) Controlling and recording instruments used for the heat treatment processes shall possess an accuracy<br />
of ± 1 % of their full-scale range.<br />
d) Temperature-controlling and -recording instruments shall be calibrated at least once every three months<br />
until a documented calibration history can be established; calibration intervals shall then be established<br />
based on repeatability, degree of usage and documented calibration history.<br />
e) Equipment used to calibrate the production equipment shall possess an accuracy of ± 0,25 % of full-scale<br />
range.<br />
7.4 Traceability<br />
7.4.1 All components, weldments, subassemblies and assemblies of SSSV equipment shall be traceable<br />
except the following:<br />
a) setting springs used to establish closure parameters for SSCSVs;<br />
b) beans for SSCSVs;<br />
c) common hardware items such as nuts, bolts, set screws and spacers.<br />
7.4.2 Traceability shall be in accordance with the manufacturer's documented procedures. All assemblies,<br />
components (including seals), weldments and subassemblies of equipment supplied shall be traceable to a<br />
job lot and a material test report. Components and weldments shall also have their included heat(s) or batch<br />
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lot(s) identified. All components and weldments in a multi-heat or multi-batch lot shall be rejected if any heat or<br />
batch does not comply with the manufacturer's specified requirements.<br />
7.4.3 Traceability for SSSV equipment is considered sufficient if the equipment meets the requirements of<br />
this International Standard when it leaves the manufacturer's inventory.<br />
7.5 Components undergoing special processes<br />
7.5.1 Coatings and overlays<br />
Application of coatings and overlays shall be controlled using documented procedures and instructions that<br />
include acceptance criteria.<br />
7.5.2 Welding and brazing<br />
Welding and brazing shall require the following.<br />
a) Welding and brazing procedure and personnel qualification shall be in accordance with ASME Boiler and<br />
Pressure Vessel Code Section IX.<br />
b) Material and practices not listed in the ASME Boiler and Pressure Vessel Code Section IX shall be<br />
applied using weld procedures qualified in accordance with the methods of ASME Boiler and Pressure<br />
Vessel Code Section IX.<br />
7.6 Quality control<br />
7.6.1 General<br />
Subclause 7.6 provides minimum quality control requirements to meet this International Standard. All quality<br />
control work shall be controlled by documented instructions that include acceptance criteria.<br />
7.6.2 Component dimensional inspection<br />
All traceable components, except non-metallic seals, shall be dimensionally inspected to assure proper<br />
function and compliance with design criteria and specifications. Inspection shall be performed during or after<br />
the manufacture of the components but prior to assembly, unless assembly is required for proper<br />
measurement.<br />
7.6.3 Non-metals inspection<br />
a) Sampling procedures and the basis for acceptance or rejection of a batch lot shall be in accordance with<br />
ISO 2859-1, general inspection level II at a 2,5 AQL for O-rings and a 1,5 AQL for other sealing elements<br />
until a documented variation history can be established. Sampling procedures shall then be established<br />
based on the documented variation history.<br />
b) Visual inspection of O-rings shall be in accordance with ISO 3601-3. Other sealing elements shall be<br />
visually inspected in accordance with the manufacturer's documented specifications.<br />
NOTE For the purposes of this provision, MIL STD 413 is equivalent to ISO 3601-3.<br />
c) Dimensional tolerances of O-rings shall be in accordance with ISO 3601-1. Other sealing elements shall<br />
meet dimensional tolerances of the manufacturer's written specifications.<br />
NOTE For the purposes of this provision, SAE AS568B is equivalent to ISO 3601-1.<br />
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d) The durometer hardness of O-rings or other elastomeric sealing elements shall be determined in<br />
accordance with ISO 48 or ASTM D 2240. A test specimen manufactured from each batch may be used.<br />
NOTE For the purposes of these provisions, ASTM D 1415 is equivalent to ISO 48.<br />
7.6.4 Surface inspection(s)<br />
The supplier/manufacturer shall have documented procedures, including acceptance criteria, for inspection of<br />
all accessible surfaces for defects and damage before assembly of the SSSV.<br />
7.6.5 Thread inspection<br />
7.6.5.1 All API tapered-thread tolerances, inspection requirements, gauging, gauging practice, gauge<br />
calibration and gauge certification shall be in accordance with API Spec 5B.<br />
7.6.5.2 All other thread tolerances, inspection requirements, gauging, gauging practice, gauge calibration<br />
and gauge certification shall conform to the specified thread manufacturer's written specifications.<br />
7.6.6 Measuring/testing equipment calibration<br />
7.6.6.1 Measuring and testing equipment used for acceptance shall be identified, inspected, calibrated<br />
and adjusted at specific intervals in accordance with documented specifications, ANSI/NCSL Z540-1, and this<br />
International Standard.<br />
7.6.6.2 Pressure measuring devices shall<br />
a) be readable to at least ± 0,5 % of full-scale range;<br />
b) be calibrated to maintain ± 2 % accuracy of full-scale range.<br />
7.6.6.3 Pressure measuring devices shall be used only within the calibrated range.<br />
7.6.6.4 Pressure measuring devices shall be calibrated with a master pressure measuring device or a<br />
dead-weight tester. Calibration intervals for pressure-measuring devices shall be a maximum of three months<br />
until documented calibration history can be established. Calibration intervals shall then be established based<br />
on repeatability, degree of usage and documented calibration history.<br />
7.6.7 NDE<br />
7.6.7.1 Requirements<br />
7.6.7.1.1 All NDE instructions shall be approved by a Level III examiner qualified in accordance with<br />
ISO 9712.<br />
NOTE For the purposes of these provisions, SNT-TC-1A is equivalent to ISO 9712.<br />
7.6.7.1.2 All primary closure springs shall be magnetic-particle or liquid-penetrant inspected for surface<br />
defects to verify conformance with the manufacturer's written specifications.<br />
7.6.7.1.3 All pressure-containing welds shall be magnetic-particle or liquid-penetrant inspected for surface<br />
defects and shall be volumetrically inspected by radiographic or ultrasonic techniques to verify conformance<br />
with the manufacturer's written specifications.<br />
7.6.7.1.4 All pressure-containing castings and forgings shall be magnetic-particle or liquid-penetrant<br />
inspected for surface defects and shall be volumetrically inspected by radiographic or ultrasonic techniques to<br />
verify conformance with the manufacturer's written specifications. The manufacturer may develop AQL<br />
inspection levels based on documented variation history.<br />
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7.6.7.2 Methods and acceptance criteria<br />
7.6.7.2.1 Liquid penetrant<br />
Liquid-penetrant inspection shall be carried out as follows:<br />
a) method: in accordance with ASTM E 165;<br />
b) acceptance criteria: in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1,<br />
Appendix 8.<br />
7.6.7.2.2 Wet magnetic particle examination<br />
Wet magnetic particle examination shall be carried out as follows:<br />
a) method: in accordance with ISO 13665 or ASTM E 709;<br />
b) indications shall be described as one of the following:<br />
1) relevant indication: only those indications with major dimensions greater than 1,6 mm (1/16 in) shall<br />
be considered relevant whereas inherent indications not associated with a surface rupture (i.e.,<br />
magnetic permeability variations, non-metallic stringers etc.) shall be considered non-relevant;<br />
2) linear indication: any indication in which the length is equal to or greater than three times its width;<br />
3) rounded indication: any indication which is circular or elliptical in which the length is less than three<br />
times its width;<br />
c) acceptance criteria:<br />
1) any relevant indication greater than or equal to 4,8 mm (3/16 in) shall be considered unacceptable;<br />
2) no relevant linear indications shall be allowed for weldments;<br />
3) no more than ten relevant indications shall be present in any 39 cm 2 (6 in 2 ) area;<br />
4) four or more rounded relevant indications in a line separated by less than 1,6 mm (1/16 in) shall be<br />
considered unacceptable.<br />
7.6.7.2.3 Ultrasonic inspection of weldments<br />
Ultrasonic inspection of weldments shall be carried out as follows:<br />
a) method: in accordance with ASME Boiler and Pressure Vessel Code, Section V, Article 5;<br />
b) acceptance criteria: in accordance with ASME Boiler and Pressure Code, Section VIII, Division 1,<br />
Appendix 12.<br />
7.6.7.2.4 Ultrasonic inspection of castings<br />
Ultrasonic inspection of castings shall be carried out as follows:<br />
a) method: in accordance with ASTM E 428 and ASTM A 609;<br />
b) acceptance criteria: in accordance with ASTM A 609 at an ultrasonic testing quality level 1, minimum.<br />
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7.6.7.2.5 Ultrasonic inspection of forgings and wrought products<br />
Ultrasonic inspection of forgings and wrought products shall be carried out as follows:<br />
a) method: in accordance with ASTM E 428 and ASTM A 388;<br />
b) calibration:<br />
1) back reflection technique: the instrument shall be set so that the first back reflection is 75 % ± 5 % of<br />
the screen height when the transducer is placed on an indication-free area of the forging or wrought<br />
product,<br />
2) flat bottom hole technique: the distance amplitude curve (DAC) shall be based on a 3,2 mm (1/8 in)<br />
flat bottom hole for thicknesses up to and including 101,6 mm (4 in) and a 6,4 mm (1/4 in) flat bottom<br />
hole for thicknesses greater than 101,6 mm (4 in),<br />
3) angle beam technique: the distance amplitude curve (DAC) shall be based on a notch of a depth<br />
equal to the lesser of 9,5 mm (3/8 in) or 3 % of the normal section thickness [9,5 mm (3/8 in)<br />
maximum], a length of approximately 25,4 mm (1 in) and a width no greater than twice its depth;<br />
c) acceptance criteria: any of the following forging or wrought product defects shall be basis for rejection:<br />
1) back reflection technique: indications greater than 50 % of the referenced back reflection<br />
accompanied by a complete loss of back reflection,<br />
2) flat bottom hole technique: indications equal to or larger than the indications observed from the<br />
calibration flat bottom hole,<br />
3) angle beam technique: amplitude of the discontinuities exceeding those of the reference notch.<br />
7.6.7.2.6 Radiographic inspection of weldments<br />
Radiographic inspection of weldments shall be carried out as follows:<br />
a) method: in accordance with ASTM E 94;<br />
b) acceptance criteria: in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1,<br />
UW-51.<br />
7.6.7.2.7 Radiographic inspection of castings<br />
Radiographic inspection of castings shall be carried out as follows:<br />
a) method: in accordance with ASTM E 94;<br />
b) acceptance criteria:<br />
1) in accordance with ASTM E 186;<br />
2) in accordance with ASTM E 280;<br />
3) in accordance with ASTM E 446.<br />
The maximum defect severity levels for 1), 2) and 3) are given in Table 1.<br />
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Table 1 — Maximum defect severity levels for castings<br />
Defect category<br />
Maximum defect severity level<br />
A 3<br />
B 2<br />
C (all types) 2<br />
D<br />
E<br />
F<br />
G<br />
None acceptable<br />
None acceptable<br />
None acceptable<br />
None acceptable<br />
NOTE The defect categories, types and severity levels are defined in ASTM E 186,<br />
ASTM E 280 and ASTM E 446, as applicable.<br />
7.6.7.2.8 Radiographic inspection of forgings<br />
Radiographic inspection of forgings shall be carried out as follows:<br />
a) method: in accordance with ASTM E 94;<br />
b) acceptance criteria of which any of the following defects shall be basis for rejection:<br />
1) any type of crack or lap;<br />
2) any other elongated indication with length, L, and wall thickness, t, as follows:<br />
⎯ L > 6,4 mm (1/4 in) for t u 19 mm (3/4 in)<br />
⎯ L > 1/3 t for 19 mm < t u 57,2 mm (3/4 in < t u 21/4 in)<br />
⎯ L > 19 mm (3/4 in) for t > 57,2 mm (21/4 in)<br />
3) any group of indications in a line that have an aggregate length greater than t in a length of 12 t.<br />
7.6.8 Personnel qualifications<br />
7.6.8.1 Personnel performing NDE evaluations and interpretations shall be qualified in accordance with<br />
ISO 9712, to at least Level II, or equivalent.<br />
NOTE For the purposes of these provisions, SNT-TC-1A is equivalent to ISO 9712.<br />
7.6.8.2 Personnel performing visual examinations shall have an annual eye examination, as applicable to<br />
the discipline to be performed, in accordance with ISO 9712.<br />
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NOTE For the purposes of these provisions, SNT-TC-1A is equivalent to ISO 9712.<br />
7.6.8.3 All other personnel performing inspection for acceptance shall be qualified in accordance with<br />
documented requirements.<br />
7.6.9 Certifications<br />
Components undergoing external processes at a subcontractor, such as heat treatment, welding or coating<br />
shall require the following:<br />
a) a certificate of conformance stating the materials and/or processes meet the manufacturer's documented<br />
specifications;<br />
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b) a material test report, where applicable, to verify the materials and/or processes meet the supplier's<br />
documented specifications.<br />
7.6.10 Manufacturing non-conformities<br />
Processing of non-conformities shall be controlled in accordance with the manufacturer's documented<br />
procedures. Weld repair shall be restricted to the weld only.<br />
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7.7 SSSV functional testing<br />
7.7.1 SSSV functional testing shall be performed by the manufacturer on each new SSSV manufactured in<br />
accordance with this International Standard.<br />
7.7.2 Results of the functional test shall be traceable to the valve tested and retained in accordance with<br />
7.9.1.1.<br />
7.7.3 Functional-test data shall be recorded, dated and signed by the personnel performing the tests. The<br />
required data is indicated in F.1.20 or F.1.21, as applicable.<br />
7.7.4 If the user/purchaser specifies, the optional functional test for minimal leakage the requirements<br />
given in annex D shall be applied.<br />
7.8 Product identification<br />
SSSV equipment furnished to this International Standard shall be permanently identified in accordance with<br />
the manufacturer's written specifications. Identification shall include the following:<br />
a) manufacturer's name or trademark;<br />
b) manufacturer's size and model;<br />
c) manufacturer's part number;<br />
d) unique identifying serial number;<br />
e) rated working pressure;<br />
f) minimum ID (TRSV only);<br />
g) class(es) of service designation.<br />
Class of service designations listed below may be combined to indicate the complete class of service. For<br />
example, 2,4 indicates sandy and mass loss corrosion service.<br />
1 — Standard service<br />
2 — Sandy service<br />
3S — Stress corrosion cracking service—sour environment<br />
3C — Stress corrosion cracking service—non-sour environment<br />
4 — Mass loss corrosion service.<br />
h) Orifice beans for velocity-type SSCSVs shall be identified by the orifice diameter.<br />
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7.9 Documentation and data control<br />
7.9.1 Retained documentation<br />
7.9.1.1 General<br />
The supplier/manufacturer shall establish and maintain documented procedures to control all documents and<br />
data that relate to the requirements of this International Standard. These documents and data shall be legible<br />
and maintained to demonstrate conformance to specified requirements. All documents and data shall be<br />
retained in facilities that provide an environment that prevents damage, deterioration, or loss. Documents and<br />
data may be in the form of any type of media, such as hard copy or electronic media. All documents and data<br />
shall be available and auditable by the user/purchaser; they shall be available within one week of request.<br />
Documentation shall be retained for a minimum of five years from the date of manufacture.<br />
7.9.1.2 Design documentation<br />
Design criteria, verification, and validation documents for each size, type and model, and the information listed<br />
below, shall be maintained for ten years after date of last manufacture:<br />
a) functional and technical specifications;<br />
b) one complete set of drawings, written specifications and standards;<br />
c) instructions providing methods for the safe assembly and disassembly of the SSSV and stating the<br />
operations which are permitted and preclude failure and/or non-compliance with the functional and<br />
performance requirements;<br />
d) material type, yield strength and connection identification for the actual end connection(s) provided with<br />
the SSSV;<br />
e) operating manual;<br />
f) contents of F.1.20 or F.1.21, as applicable, and F.1.22 are a minimum data requirement for the<br />
documentation specified in this subclause;<br />
g) validation test files shall contain sufficient documentation to identify and permit retrieval of<br />
1) all drawings and specifications applicable at the time of manufacture,<br />
2) all applications for validation tests or retests,<br />
3) all design and/or material modifications, or other justification for retest, of SSSV equipment and seals<br />
which did not pass any validation test,<br />
4) all test data specified in this subclause.<br />
7.9.2 Supplied documentation<br />
7.9.2.1 General<br />
SSSVs shall be delivered with a manufacturer's shipping report and an operating manual. F.1.22 contains<br />
shipping-report requirements for SSSVs.<br />
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7.9.2.2 Operating manual contents<br />
a) size, type and model;<br />
b) class(s) of service;<br />
c) operating data as follows:<br />
⎯<br />
⎯<br />
⎯<br />
⎯<br />
⎯<br />
⎯<br />
working pressure,<br />
temperature range,<br />
internal yield pressure,<br />
collapse pressure (applies to tubing-retrievable SSSV equipment at maximum rated temperature),<br />
tensile load strength (applies to tubing-retrievable SSSV equipment at maximum rated temperature),<br />
operating envelope, if specified by the user/purchaser (see example in Annex E);<br />
d) dimensional data, including dimensions of drift bar and drift sleeve, if applicable;<br />
e) calculations as follows:<br />
⎯<br />
⎯<br />
SCSSVs — Calculation procedures used to determine maximum fail-safe setting depths, where<br />
applicable,<br />
SSCSVs — Orifice coefficients, spring force, optimum operating range of pressure differential for<br />
velocity-type valves, etc.;<br />
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f) drawings and illustrations;<br />
g) parts list with all necessary information for reordering, including manufacturer's contact information;<br />
h) specific details of functional testing should be included if the test apparatus or procedures are significantly<br />
different than those included in this International Standard;<br />
i) running instructions;<br />
j) pulling instructions;<br />
k) inspection and testing procedures;<br />
l) installation and operating procedures;<br />
m) troubleshooting and maintenance procedures;<br />
n) repair limitations;<br />
o) redress disassembling and reassembling requirements;<br />
p) operating requirements as follows:<br />
⎯<br />
SCSSVs:<br />
1) opening and closing procedures with opening and closing pressures,<br />
2) equalizing procedure, including maximum recommended unequalized opening pressure,<br />
⎯<br />
SSCSVs:<br />
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3) opening or equalization procedures,<br />
4) optimum conditions to avoid nuisance closures and throttling;<br />
q) Storage recommendations.<br />
7.10 Failure reporting and analysis<br />
7.10.1 This subclause provides the requirements for processing the user/purchaser provided failure reports<br />
as defined in ISO 10417. The supplier/manufacturer shall have documented procedures that define the<br />
actions required.<br />
7.10.2 Notification of the receipt of a failure report shall be provided to the submitting user/purchaser contact<br />
within 30 calendar days of the documented receipt at the manufacturer. This notification shall include any data<br />
collection requests that the manufacturer needs to perform an effective evaluation and a projected completion<br />
date of the evaluation. Should the requested data or equipment not be provided as requested, the failure<br />
report becomes inactive 30 calendar days after the notification has been provided to the user/purchaser.<br />
7.10.3 Following receipt of the requested data and equipment to be analyzed, reasonable efforts shall be<br />
implemented to complete the evaluations in a timely manner that meets the prevailing business need. The<br />
evaluation report shall be provided to the user/purchaser within 15 calendar days after completion of the<br />
evaluation. This evaluation shall include the actions required of the user/purchaser to mitigate reoccurrence of<br />
the identified problem and suggested measures to extend the product's operational life, when appropriate.<br />
The manufacturer shall make necessary design changes that result from the failure analysis on all affected<br />
SSSV equipment. If the required or suggested actions apply to similar products, they shall be referenced in<br />
the evaluation.<br />
7.10.4 Evaluations and any subsequent notifications prepared in response to a failure report shall be<br />
documented and available for three years after the date of preparation.<br />
8 Repair/redress<br />
8.1 Repair<br />
Repair operations for SSSVs shall include the return of the product to a condition meeting all requirements<br />
stated in this International Standard or the edition of this International Standard in effect at the time of original<br />
manufacture.<br />
8.2 Redress<br />
Redress operations are beyond the scope of this International Standard. ISO 10417 provides requirements for<br />
SSSV equipment redress.<br />
9 Storage and preparation for transport<br />
9.1 SSSV equipment shall be stored per the written specifications of the equipment manufacturer to prevent<br />
deterioration (for example, caused by atmospheric conditions, debris, radiation, etc.) prior to transport.<br />
9.2 SSSV equipment shall be packaged for transport per the written specifications of the equipment<br />
manufacturer to prevent normal handling loads and contamination from harming the equipment. These<br />
specifications shall address the protection of: external sealing elements, sealing surfaces, exposed threaded<br />
connections, access port(s) sealing and contamination from fluids and debris.<br />
9.3 All material provided as protection for transport shall be clearly identified for removal prior to equipment<br />
use.<br />
9.4 For storage after transport, see operating manual.<br />
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ISO 10432:2004(E)<br />
Annex A<br />
(normative)<br />
Test agency requirements<br />
A.1 General<br />
The test agency shall meet the requirements of Annex A and have the ability to perform the tests of Annex B<br />
in order to conduct validation tests. Any variation from the validation test requirements of this International<br />
Standard shall be noted on the test application and recorded on the validation test data summary (see F.1.13)<br />
by the test agency.<br />
The test agency shall conduct validation tests as specified on the manufacturer's test application in F.1.1 and<br />
record the results of the validation test as specified in F.1.13. The content of Annex F, as applicable, is a<br />
minimum data requirement for the documentation specified in this subclause. The test agency shall supply a<br />
copy of the validation test report to the manufacturer within thirty days of the completion of the test. This report<br />
shall be retained by the manufacturer and by the test agency, and shall be available to the user/purchaser<br />
upon request to the manufacturer.<br />
Test agencies performing validation testing shall conform to ISO/IEC 17025.<br />
The test agency shall provide, on written request, current documentation to manufacturer or user/purchaser.<br />
This shall include the following, as a minimum:<br />
a) description of the facility, including any limitations on the size, length, mass, type, pressure rating,<br />
temperature rating, and service class of SSSV that may be tested;<br />
b) test procedures and forms actually used at the facility for each type and service class of SSSV;<br />
c) procedures for maintenance and calibration of measuring equipment used for test acceptance, and<br />
calibration records;<br />
d) procedures for making applications for tests, the delivery of SSSVs, the initial installation and checkout of<br />
SSSVs and other pertinent information;<br />
e) any limitations on the accessibility of the facility (such limitations shall not preclude reasonable access to<br />
the facility for inspection by manufacturers or user/purchasers);<br />
f) any limitations on the receipt of proprietary information.<br />
The test agency shall promptly provide a response to the test application requestor, stating acceptance or<br />
rejection of the requirements therein. A test application may be declined if the data are incomplete, inaccurate<br />
or self-conflicting. Any declined applications shall detail the specific provisions causing rejection.<br />
A.2 Test facility requirements<br />
A.2.1 The components of the test facility systems shall have a capacity and working pressure as required by<br />
the size and/or working pressure of the SSSV to be tested. Typical test facility schematics, the SSSV gas flow<br />
facility, the liquid test facility and the controlled-temperature test facility are shown in Figures F.1, F.2, and F.4.<br />
The control pressure system components shall, as a minimum, consist of the items listed below:<br />
a) hydraulic-fluid reservoir with a filtered vent;<br />
b) accumulator;<br />
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c) hydraulic pump;<br />
d) control system to operate the pump;<br />
e) pressure relief facility to protect the system.<br />
A.2.2 There shall be provision for the supply of nitrogen gas to conduct the required nitrogen leak test and a<br />
gas flow meter to indicate the leakage rate.<br />
A gas reservoir with a gas release device and instrumentation to measure the test parameters shall be<br />
provided.<br />
The test facility shall, as a minimum, consist of the items listed below:<br />
a) test facility piping, which shall be at least 50,8 mm (2 in) nominal diameter;<br />
b) fresh-water tank;<br />
c) sand slurry tank;<br />
d) Marsh funnel viscometer in accordance with ISO 10414-1 with required timer and graduated beaker;<br />
NOTE For the purposes of these provisions, API RP 13B1 is equivalent to ISO 10414-1.<br />
e) centrifuge with basic sediment and water (BS&W) sample flasks in accordance with API Manual of<br />
Petroleum Measurement, Chapter 10.4;<br />
f) circulation pumps;<br />
g) flow meter;<br />
h) pressure measurement systems;<br />
i) time-based recorder to simultaneously record the required pressure and flow data;<br />
j) back-pressure regulator;<br />
k) propane system as shown in Figure F.5;<br />
l) high-pressure water pump and accumulator system.<br />
A.3 Validation test reports<br />
Test reports completed by a test agency conforming to this International Standard shall be traceable to the<br />
equipment tested and shall include the following:<br />
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a) general information (date, location, manufacturer, model, serial number, size, rating, etc.);<br />
b) summary of test results;<br />
c) description of the characteristics of equipment under test;<br />
d) observed data (including calculations and details of test personnel);<br />
e) test conditions (limits required by the standard);<br />
f) identification of test methods and procedures;<br />
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g) supporting data (log sheets, etc.);<br />
h) graphical presentation of operating pressure traces;<br />
i) identification of instruments involved in the testing;<br />
j) copy of validation test application from F.1.1;<br />
k) the content of the data requirements of F.1, as applicable;<br />
l) certificate of compliance in accordance with a national or internationally recognized standard such as<br />
ISO/IEC Guide 22;<br />
m) time-based testing data, as requested.<br />
A.4 Test agency records<br />
Unless otherwise specified in the appropriate referenced standard(s), the test agency shall keep the following<br />
records for ten years from completion of all tests on all equipment tested:<br />
a) test data and test reports, Annex F, as applicable;<br />
b) measuring and test equipment calibration data;<br />
c) non-conformance reports;<br />
d) audit and corrective-action records;<br />
e) personnel qualification records;<br />
f) test procedures;<br />
g) data on any special testing.<br />
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API Specification 14A / ISO 10432<br />
Annex B<br />
(normative)<br />
Validation testing requirements<br />
B.1 General<br />
To pass the validation test, the SSSV shall successfully complete all steps of the validation-testing procedure<br />
within the limits specified and in the order shown.<br />
Validation testing shall be discontinued if the valve fails to perform within the limits specified for any step<br />
except when such failures are determined to be a result of actions by the test agency or a failure within the<br />
test facility. The basis for discontinuing the test, and any unusual conditions observed at or prior to the time of<br />
discontinuance, shall be noted on the test data form by the test agency.<br />
All pressures are defined as gauge unless otherwise specified and shall be recorded on time-based<br />
equipment.<br />
Prior to any liquid pressure test, purge with test liquid to remove air.<br />
Gas pressure-relieving (bleed-down) operations shall be performed per the manufacturer's requirements.<br />
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During validation testing of hydraulically operated SSSVs, control line fluid metering may be used to provide a<br />
readable hydraulic control line pressure trace. Refer to Figure F.6 for a characteristic pressure versus time<br />
plot for opening and closing hydraulic control pressures with hydraulic fluid being applied at a metered rate.<br />
When validation testing of SSSV sizes not covered in Tables F.1, F.2, and F.3, the flow rate values may be<br />
interpolated or extrapolated by a ratio of the square of the diameter versus the parameter involved.<br />
The test section shall completely enclose a wireline-retrievable SSSV. Tubing-retrievable SSSVs shall be an<br />
integral part of the test section. The test section shall be rated to at least the rated working pressure of the<br />
SSSV.<br />
The test section ends, length and hydraulic control connections shall be compatible with the test agency's<br />
facility.<br />
Each data form shall be signed and dated by the person(s) conducting the test. The form containing the data<br />
specified in F.1.13 shall be signed and dated by the test agency's designated approval authority.<br />
B.2 Validation test procedure — SCSSV<br />
B.2.1 General<br />
Verify that the model and serial numbers appearing on the test valve are in agreement with the manufacturer's<br />
application.<br />
B.2.2 Class 1 test<br />
B.2.2.1<br />
B.2.2.2<br />
Perform the SCSSV gas flow test (see B.3).<br />
Open the test valve. Record the full-open hydraulic control pressure as shown in F.1.4.<br />
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B.2.2.3 Fill the test valve with water and circulate water to displace gas out of the test section. Once gas<br />
has been displaced from the test section, discontinue water circulation.<br />
B.2.2.4<br />
B.2.2.5<br />
B.2.2.6<br />
B.2.2.7<br />
B.2.2.8<br />
B.2.2.9<br />
B.2.2.10<br />
B.2.2.11<br />
B.2.2.12<br />
B.2.2.13<br />
B.2.2.14<br />
B.2.2.15<br />
Close the test valve. Record the full-closed hydraulic control pressure as shown in F.1.4.<br />
Perform the liquid leakage test (see B.5).<br />
Perform the unequalized opening test (see B.6).<br />
Perform the operating-pressure test (see B.7).<br />
Perform the propane test (see B.8).<br />
Perform the nitrogen leakage test (see B.9).<br />
Repeat the operating-pressure test (see B.7).<br />
Perform the SCSSV Class 1 flow test (see B.10).<br />
Repeat B.2.2.9 to B.2.2.11 four additional times.<br />
Perform the liquid leakage test (see B.5).<br />
Perform the controlled-temperature test (see B.11).<br />
If the test valve is being qualified for Class 1 service only, proceed to B.2.3.6.<br />
B.2.3 Class 2 test<br />
B.2.3.1<br />
B.2.3.2<br />
Perform the nitrogen leakage test (see B.9).<br />
Perform the operating-pressure test (see B.7).<br />
B.2.3.3 Perform the Class 2 flow test (see B.12). Class 2 flow testing shall be performed in a continuous<br />
manner with no interruptions longer than 2 h.<br />
B.2.3.4<br />
B.2.3.5<br />
B.2.3.6<br />
Repeat B.2.3.1 to B.2.3.3 six additional times.<br />
Perform the liquid leakage test (see B.5).<br />
Perform the drift test (see B.4).<br />
NOTE If at any point in the Class 2 test the valve fails and it is desired to have Class 1 qualification, perform the<br />
Class 1 drift test to confirm Class 1qualification.<br />
B.2.3.7<br />
B.2.3.8<br />
If the test valve has performed within the limits specified, it has passed the validation test.<br />
Summarize the validation test data as specified in F.1.13.<br />
B.3 Gas flow test — SCSSV<br />
B.3.1<br />
Record test data as specified in F.1.2.<br />
B.3.2 Install the test valve in the gas flow test stand. The test medium shall be air, nitrogen or any other<br />
suitable gas.<br />
B.3.3<br />
Set the control line resistance to the appropriate setting shown in Table F.1.<br />
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⎯<br />
⎯<br />
⎯<br />
The test flow rates specified in Table F.1 are based on a pressure of 13,8 MPa (2 000 psi) and a velocity<br />
of 6,10 m/s (20 ft/s) in the tubing for valve closure test 1 and test 4, a velocity of 9,15 m/s (30 ft/s) for<br />
test 2, and a velocity of 3,05 m/s (10 ft/s) for test 3.<br />
The test flow rates shall be maintained within − 5 % and + 15 % of the nominal value given in Table F.1 or<br />
between −(0,01 × 10 6 ) m 3 and +(0,04 × 10 6 ) m 3 /d [−(0,5 × 10 6 ) scf and +(1,5 × 10 6 ) scf per day],<br />
whichever is greater. The low control line resistance test shall be performed with a hydraulic control line<br />
having an inside diameter of at least 9,6 mm (0,38 in) and a maximum total length of 7,6 m (25 ft).<br />
The configuration for the high control line resistance test shall consist of the control line used for the<br />
low-resistance configuration plus a square-edge orifice having an inside diameter of 0,5 mm ± 0,05 mm<br />
(0,020 in ± 0,002 in) and a length of 25,4 mm ± 2,5 mm (1,0 in ± 0,1 in).<br />
B.3.4<br />
Open and close the test valve. Record the full-open and full-closed control pressures.<br />
B.3.5 Close the flow control valve and bleed valve (see Figure F.1). Set the flow control valve to provide a<br />
gas flow at a test rate in accordance with Table F.3.<br />
B.3.6<br />
B.3.7<br />
Increase the gas pressure in the system to between 13,8 MPa (2 000 psi) and 17,3 MPa (2 500 psi).<br />
Open the test valve. Record the full-open control pressure.<br />
B.3.8 Establish and maintain the gas flow rate indicated in Table F.1, and then close the test valve while<br />
recording the control line pressure and gas flow rate.<br />
B.3.9 The test valve shall shut off a minimum of 95 % of the specified flow in 5,0 s or less after the hydraulic<br />
control pressure reaches zero, or the test valve fails the test. Record the time required by the test valve to<br />
shut off the specified flow. If the test valve fails, discontinue testing.<br />
B.3.10 Bleed the valve bore downstream pressure to zero. Adjust the test valve upstream bore pressure to<br />
8,3 MPa ± 0,4 MPa (1 200 psi ± 60 psi). Record the test valve bore upstream pressure and gas leakage rate.<br />
If leakage exceeds 0,14 m 3 /min (5 scf/min) of gas, the test valve fails. If the test valve fails, discontinue testing.<br />
B.3.11 Bleed all pressure to zero. Repeat step B.3.3 to step B.3.10 until all four closure tests specified in<br />
Table F.1 are successfully completed or until the test valve fails.<br />
B.4 Drift test — SCSSV<br />
B.4.1 General<br />
The manufacturer shall provide the test agency with a drift sleeve (for WRSVs) and/or drift bar (for TRSVs and<br />
WRSVs) that is appropriate for detecting changes in the valve's dimensions. Each drift bar/sleeve shall be<br />
permanently marked with a unique identifier. Drift bar dimensions (measured) and unique identifier shall be<br />
recorded along with the minimum specified ID of the test valve (TRSVs and WRSVs) or maximum specified<br />
OD of the test valve (WRSVs).<br />
Drift bars shall be of no smaller OD than the valve's specified minimum ID, less 0,75 mm (0,030 in); drift<br />
sleeves shall be no larger on the ID than the valve's specified maximum OD plus 0,75 mm (0,030 in), and<br />
shall be a full round at the recorded drift dimensions.<br />
Each drift bar shall be of a length designated as appropriate to verify that the product provides no restriction to<br />
the passage of tools for the full length of the product and shall be a minimum length of four times the specified<br />
inside diameter of the product, or 610 mm (24 in), whichever is greater.<br />
Each drift sleeve shall be of a length designated as appropriate to verify that the product can be received into<br />
its intended receptacle and shall be a minimum length of two times the specified outside diameter of the<br />
product.<br />
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B.4.2 Drift test — TRSV<br />
B.4.2.1<br />
B.4.2.2<br />
Record test data as specified in F.1.3.<br />
Open and close the test valve, recording the full-open hydraulic control pressure.<br />
B.4.2.3 Orient the test valve so that the valve is vertical, upside down, and in the normal open position.<br />
The test valve may be opened prior to repositioning.<br />
B.4.2.4 Pass the drift bar completely through the test valve in a manner that does not cause the test<br />
valve's closure mechanism to be opened. The drift bar shall be aided by a force no greater than that of gravity<br />
while being passed down and back through the test valve. If the drift bar does not pass freely completely<br />
through the test valve, the test valve fails.<br />
B.4.3 Drift test — WRSV<br />
B.4.3.1<br />
Record test data as specified in F.1.3.<br />
B.4.3.2 Open the test valve, recording the full-open hydraulic control pressure. Orient the test valve so<br />
that the valve is vertical, upside down, and in the normal open position.<br />
B.4.3.3 Pass the drift bar completely through the test valve in a manner that does not cause the test<br />
valve's closure mechanism to be opened. The drift bar shall be aided by a force no greater than that of gravity<br />
while being passed down and back through the test valve. If the drift bar does not pass freely completely<br />
through the test valve, the test valve fails.<br />
B.4.3.4 Pass the drift sleeve over the entire length, except for the packing stack/sealing device, of the test<br />
valve in a manner that does not cause the test valve's closure mechanism to be moved.<br />
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NOTE<br />
If control line or control sleeve is in place, a partial drift of the lower valve can be accomplished here.<br />
Close the test valve and record the closing pressures. If a partial OD drift has been accomplished, pass the<br />
drift sleeve over the remaining length of the test valve. The drift sleeve shall be aided by a force no greater<br />
than that of gravity while being passed down and back over the test valve. If the drift sleeve does not freely<br />
pass completely over the test valve, except for the packing stack/sealing device, the test valve fails.<br />
B.5 Liquid leakage test — SSSV<br />
B.5.1<br />
B.5.2<br />
Record test data as specified in F.1.5.<br />
Make certain that the test valve is in the closed position with only liquid above and below the valve.<br />
B.5.3 Apply water pressure upstream of the test valve closure mechanism at 100 % of the rated working<br />
pressure (allowable range of 95 % to 100 %) of the valve. Record the test valve bore pressure and the time at<br />
which pressure was applied to the valve.<br />
B.5.4 Wait for a minimum of 3 min after applying water pressure upstream of the test valve closure<br />
mechanism before beginning collection of water leakage from the downstream bleed valve.<br />
Continuously collect water leakage for a period of 5 min. Record the times at which water leakage collection<br />
began and ended and the amount of water collected. Calculate and record the average leakage rate. If the<br />
average leakage rate during the collection period exceeds 10 cm 3 /min of water, or if external body leakage is<br />
detected (tubing-retrievable only), the test valve fails. If the test valve fails, discontinue testing.<br />
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API Specification 14A / ISO 10432<br />
B.6 Unequalized opening test — SCSSV<br />
B.6.1<br />
Record test data as specified in F.1.6.<br />
B.6.2 Establish water pressure upstream of the test valve closure mechanism at the maximum<br />
manufacturer-specified opening-pressure differential.<br />
B.6.3 Open the test valve closure mechanism against pressure as recommended in the test valve-operating<br />
manual. Record the equalizing pressure and the full-open hydraulic control pressure.<br />
B.7 Operating-pressure test — SCSSV<br />
B.7.1<br />
Record test data as specified in F.1.7.<br />
B.7.2 Apply pressure of 25 % of the rated working pressure (allowable range of 20 % to 30 % of rated<br />
working pressure) of the test valve to the entire test section. Record the test valve bore pressure (base<br />
pressure).<br />
B.7.3 Close and open test valve five times while maintaining the test section pressure recorded in B.7.2<br />
within the specified range.<br />
NOTE The test section pressure can increase as the valve is opened, and then can decrease as the valve is closed<br />
due to the differential volume of the hydraulic operating piston.<br />
The full-open/full-closed hydraulic control pressures shall be adjusted based on the change in test section<br />
pressure at the time of control pressure measurement. The adjusted control pressure is determined by<br />
adding/subtracting the actual control pressure with the difference between the base pressure and the actual<br />
test section pressure recorded at the time of each opening/closing pressure measurement. If the five adjusted<br />
hydraulic control pressures do not repeat within ± 10 % of their average, or ± 0,7 MPa (± 100 psi), whichever<br />
is greater, or if any body joint leakage (tubing-retrievable only) is detected, the test valve fails.<br />
B.7.4 Repeat B.7.2 and B.7.3 at 75 % of the rated working pressure (allowable range of 70 % to 80 % of<br />
rated working pressure).<br />
B.8 Propane test — SCSSV (SSCSV as noted)<br />
B.8.1<br />
Record test data as specified in F.1.8.<br />
B.8.2 Open the test valve. Displace liquid out of the test section with nitrogen at a downstream location and<br />
bleed the nitrogen pressure to zero.<br />
B.8.3 Cycle the test valve closed and open three times. Leave the test valve open. Record the full-closed<br />
and full-open hydraulic control pressures. If the three hydraulic control pressures do not repeat within ± 10 %<br />
of their averages or ± 0,7 MPa (100 psi), whichever is greater, the test valve fails.<br />
B.8.4 Transfer propane to the test section until the test section pressure reaches 2,8 MPa ± 0,14 MPa<br />
(400 psi ± 20 psi).<br />
B.8.5 Open the downstream vent valve until liquid propane is expelled, close the propane vent valve, and<br />
adjust the pressure to 2,8 MPa ± 0,14 MPa (400 psi ± 20 psi). Record the test valve bore pressure.<br />
B.8.6 Close and open the test valve three times, leaving the test valve in each position (opened or closed)<br />
for a minimum of 15 min. Record the full-open and full-closed hydraulic control pressures.<br />
NOTE The test section pressure can increase as the valve is opened, and then can decrease as the valve is closed<br />
due to the differential volume of the hydraulic operating piston.<br />
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ISO 10432:2004(E)<br />
The full-open/full-closed hydraulic control pressures shall be adjusted based on the change in test section<br />
pressure at the time of control pressure measurement. The adjusted control pressure is determined by<br />
adding/subtracting the actual control pressure with the difference between the base pressure and the actual<br />
test section pressure recorded at the time of each opening/closing pressure measurement. If the three<br />
adjusted hydraulic control pressures do not repeat within ± 10 % of their average, or ± 0,7 MPa (± 100 psi),<br />
whichever is greater, or if any body joint leakage (tubing-retrievable only) is detected, the test valve fails<br />
B.8.7 Leave the test valve in the open position in propane for an additional 2 h, minimum. Record the start<br />
and completion times and the valve bore pressure at the end of the 2 h interval.<br />
B.8.8<br />
B.8.9<br />
Bleed the section pressure to zero.<br />
Purge the test section with nitrogen.<br />
B.8.10 Close the test valve and record the full-closed hydraulic control pressure.<br />
B.9 Nitrogen leakage test — SCSSV (SSCSV as noted)<br />
B.9.1<br />
Record test data as specified in F.1.9.<br />
B.9.2 Apply 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) nitrogen pressure upstream of the test valve. Wait a<br />
minimum of 1 min, then measure any nitrogen leakage through the closure mechanism. Record the test valve<br />
bore pressure, the leakage rate and the start and completion times of the waiting period. If the leakage rate is<br />
greater than 0,14 m 3 /min (5 scf/min), or if any body joint leakage (tubing-retrievable only) is detected, the test<br />
valve fails.<br />
B.9.3 Repeat B.9.2 at 25 % of the rated working pressure (allowable range of 20 % to 30 % of rated working<br />
pressure) of the test valve.<br />
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B.9.4<br />
B.9.5<br />
Bleed the pressure upstream of the test valve to zero.<br />
Open the test valve. Record the full-open hydraulic control pressure.<br />
B.10 Class 1 flow test — SCSSV<br />
B.10.1 Record test data as specified in F.1.10.<br />
B.10.2 Circulate fresh water through the system while bypassing the test valve until gas has been displaced<br />
from the system.<br />
B.10.3 Adjust the water flow rate through the test valve to obtain a stable flow at the value specified in<br />
Table F.2. Record the time at which flow is directed through the test valve. Pass water through the test valve<br />
at the specified rate for a minimum of 5 min.<br />
B.10.4 Close the test valve against the flow. Record the full-closed hydraulic control pressure and the water<br />
flow rate through the test valve at the time closure was initiated. The test valve shall shut off a minimum of<br />
95 % of the specified flow at the first closure attempt in 15,0 s or less after the hydraulic control pressure<br />
reaches zero, or the test valve fails. Record the time required by the test valve to shut off the specified flow.<br />
B.10.5 Open the test valve. Record the full-open hydraulic control pressure.<br />
B.10.6 Repeat B.10.2 to B.10.4 until the three fresh-water closure rates have been completed or the test<br />
valve fails.<br />
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ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
B.11 Controlled-temperature test — SCSSV<br />
B.11.1 Record test data as specified in F.1.11.<br />
B.11.2 Install the test valve in the controlled-temperature test stand. Temperature measurements shall be<br />
taken in the area of the control line entry port of the test valve.<br />
B.11.3 Allow the test valve to reach a stable temperature of 38 °C ± 3 °C (100 °F ± 5 °F).<br />
B.11.4 Apply nitrogen gas pressure of 25 % of the rated working pressure (allowable range of 20 % to 30 %<br />
of rated working pressure) of the test valve. Allow the temperature at the test valve to stabilize. Record the<br />
test valve temperature and the test valve bore pressure (base pressure).<br />
B.11.5 Cycle the test valve ten times while maintaining the specified test valve temperature and pressure<br />
recorded in B.11.4 within the specified ranges.<br />
NOTE The test section pressure can increase as the valve is opened, and then can decrease as the valve is closed<br />
due to the differential volume of the hydraulic operating piston.<br />
The full-open/full-closed hydraulic control pressures shall be adjusted based on the change in test section<br />
pressure at the time of control pressure measurement. The adjusted control pressure is determined by<br />
adding/subtracting the actual control pressure with the difference between the base pressure and the actual<br />
test section pressure recorded at the time of each opening/closing pressure measurement. If the ten adjusted<br />
hydraulic control pressures do not repeat within ± 10 % of their average, or ± 0,7 MPa (± 100 psi), whichever<br />
is greater, or if any body joint leakage (tubing-retrievable only) is detected, the test valve fails.<br />
B.11.6 Connect a tube from the test valve hydraulic control line port to a container filled with water. Position<br />
the tube so any gas bubbles from the hydraulic control line port can be observed.<br />
B.11.7 With the test valve bore filled with nitrogen gas at the specified temperature and pressure, wait a<br />
minimum of 3 min and then observe for gas bubble leakage continuously for a minimum of 5 min. Record the<br />
times at which the 3 min waiting period, preceding the leakage test, begins and ends and the times at which<br />
the 5 min gas bubble leakage observation period begins and ends. If continuous leakage from the control line<br />
is observed for at least 1 min during the observation period, or if body joint leakage (tubing-retrievable only) is<br />
detected, the test valve fails.<br />
B.11.8 Repeat B.11.3 to B.11.7 using a test valve bore pressure of 75 % of the rated working pressure<br />
(allowable range of 70 % to 80 % of rated working pressure) of the test valve.<br />
B.11.9 Bleed nitrogen pressure above the closure mechanism to zero. Adjust and stabilize the pressure<br />
below the closure mechanism to 75 % of the rated working pressure (allowable range of 70 % to 80 % of rated<br />
working pressure) of the test valve. Wait a minimum of 1 min, then measure any nitrogen leakage across the<br />
closure mechanism. Record the test valve bore pressure below the closure mechanism, any leakage, and the<br />
start and completion times of the waiting period. If the leakage rate is greater than 0,14 m 3 /min (5 scf/min), or<br />
if any body joint leakage (tubing-retrievable only) is detected, the test valve fails.<br />
B.11.10 Repeat B.11.3 to B.11.8 using a stabilized temperature of 82 °C ± 3 °C (180 °F ± 5 °F).<br />
B.11.11 Bleed all pressure to zero. Allow the test valve to cool. Remove the test valve from the<br />
controlled-temperature test stand.<br />
B.12 Class 2 flow test — SCSSV<br />
B.12.1 Record test data as specified in F.1.12.<br />
B.12.2 Prepare a slurry consisting of sand and viscosified water.<br />
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B.12.3 Determine the sand content of the slurry in accordance with the API Manual of Petroleum<br />
Measurement Standards, Chapter 10.4. Adjust the sand content to 2 % ± 0,5 % by adding 150 µm to 180 µm<br />
(100 U.S. mesh to 80 U.S. mesh) sand or by diluting the slurry with fresh water.<br />
B.12.4 Determine the viscosity of the slurry sample with a Marsh funnel viscometer in accordance with<br />
ISO 10414-1. Adjust the viscosity to 70 s ± 5 s by adding a viscosifier or diluting the slurry with fresh water.<br />
NOTE For the purposes of these provisions, API RP 13B1 is equivalent to ISO 10414-1.<br />
B.12.5 The viscosity and sand content requirements specified above shall be met before proceeding.<br />
B.12.6 Adjust the slurry circulation rate to the value specified in Table F.2. Record the slurry circulation rate,<br />
sand content and slurry viscosity. Record the time at which the slurry circulation begins.<br />
B.12.7 Circulate the slurry through the test valve at the specified rate for a minimum of 1 h, and then close<br />
the test valve against the specified rate.<br />
B.12.8 Record the full-closed hydraulic control pressure and the slurry flow rate through the test valve at the<br />
time closure is initiated. The test valve shall shut off a minimum of 95 % of the specified flow at the first<br />
closure attempt in 15,0 s or less after the hydraulic control pressure reaches zero or the test valve fails.<br />
Record the time required for the test valve to shut off the specified flow. If the test valve fails, discontinue<br />
testing.<br />
B.12.9 At the completion of the flow period, measure and record the sand content of the slurry and the slurry<br />
viscosity.<br />
B.13 Validation test procedure — SSCSV<br />
B.13.1 Verify that the model and serial numbers appearing on the test valve assembly are in agreement with<br />
the manufacturer's application.<br />
B.13.2 Perform the SSCSV gas closure test (B.14). For velocity-type SSCSVs, use the gas flow test stand to<br />
conduct the test.<br />
B.13.3 Perform the initial liquid closure test (B.15) using water as the test medium.<br />
B.13.4 Perform the liquid leakage test (B.5).<br />
B.13.5 Perform the propane test (B.8), omitting B.8.2 and B.8.5. Replace B.8.9 with: “Conduct the liquid<br />
closure test (B.15), using water as the test medium.” Record the results as specified in F.1.16. The closing<br />
flow rate for a velocity-type SSCSV or the closing pressure for a tubing-pressure-type SSCSV shall repeat<br />
within ± 15 % of the closing flow rate or pressure of B.13.3 or the test valve fails the test. If the test valve fails,<br />
discontinue testing.<br />
B.13.6 Perform the nitrogen leakage test (B.9), omitting B.9.4. Record the results as specified in F.1.17.<br />
B.13.7 Perform the SSCSV Class 1 flow test (B.16).<br />
B.13.8 Repeat B.13.6 and B.13.7 fourteen additional times. The closing flow rate for velocity-type SSCSVs or<br />
the closing pressure for tubing-pressure-type SSCSVs shall repeat within ± 15 % of the closing flow rate or<br />
pressure of B.13.3 above, or the valve fails the test. If the test valve fails, discontinue testing.<br />
B.13.9 Perform the liquid leakage test (see B.5). If the test valve is being qualified for Class 1 service only,<br />
proceed to B.13.14.<br />
B.13.10 Perform the nitrogen leakage test (see B.9), omitting B.9.4.<br />
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B.13.11 Perform the Class 2 flow test (see B.17). Class 2 flow testing shall be performed in a continuous<br />
manner with no interruptions longer than 2 h.<br />
B.13.12 Repeat B.13.10 and B.13.11 six additional times. The closing flow rate for a velocity-type SSCSV or<br />
the closing pressure for a tubing-pressure-type SSCSV shall repeat within ± 15 % of the closing flow rate or<br />
pressure of B.13.3, or the test valve fails the test.<br />
B.13.13 Perform the liquid leakage test (see B.5).<br />
B.13.14 If the test valve has performed within the limits specified, it has passed the validation test.<br />
B.13.15 Summarize the validation test data as specified in F.1.13.<br />
B.14 Gas closure test — SSCSV<br />
B.14.1 Record test data as specified in F.1.14.<br />
B.14.2 Increase gas pressure in the system to between 13,8 MPa (2 000 psi) and 17,3 MPa (2 500 psi).<br />
B.14.3 Close the test valve as follows.<br />
a) Velocity-type SSCSVs — Increase the gas flow rate through the test valve until the test valve closes. The<br />
test valve shall close at a flow rate of at least ± 25 % of the design closing flow rate indicated in F.1.1 in<br />
30 s or less from the time this flow rate is achieved, or the test valve fails the test. If the test valve fails,<br />
discontinue testing. Record the initial pressure upstream of the test valve, the differential pressure across<br />
the test valve closure mechanism, and the gas flow rate through the test valve at closure.<br />
b) Tubing-pressure-type SSCSVs — Adjust the gas pressure downstream of the test valve to ensure the test<br />
valve is open. Decrease the downstream pressure until the test valve closes. The test valve shall close at<br />
a downstream pressure of at least 75 % of the design closing pressure indicated in F.1.1. The minimum<br />
allowable downstream pressure is 0,35 MPa (50 psi). The test valve shall close in 30 s or less from the<br />
time this minimum pressure is achieved, or the test valve fails the test. Record the initial pressure<br />
downstream of the test valve and the pressure downstream of the test valve at closure. If the test valve<br />
fails, discontinue testing.<br />
B.14.4 Bleed the valve bore downstream pressure to zero. Adjust the test valve bore upstream pressure to<br />
8,3 MPa (1 200 psi) ± 5 %. Wait a minimum of 1 min, then measure any gas leakage through the closure<br />
mechanism. Record the test valve bore pressure, the leakage rate and the start and completion times of the<br />
waiting period. If the leakage rate is greater than 0,14 m 3 /min (5 scf/min), the test valve fails. If the test valve<br />
fails, discontinue testing.<br />
B.14.5 Bleed all pressure to zero.<br />
B.15 Liquid closure test — SSCSV<br />
B.15.1 Record test data as specified in F.1.15.<br />
B.15.2 Circulate liquid through the system while bypassing the test valve until gas has been displaced from<br />
the system.<br />
B.15.3 Adjust the circulation rate through the test valve to obtain a flow at the rate specified in Table F.3.<br />
B.15.4 Close the test valve as follows.<br />
a) Velocity-type SSCSVs — Adjust the pressure downstream of the test valve to between 0,35 MPa and<br />
0,38 MPa (50 psi and 55 psi). Increase the circulation rate through the valve until the valve closes. The<br />
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API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
circulation rate shall be increased such that the pressure downstream of the test valve can be maintained<br />
between 0,35 MPa and 0,38 MPa (50 psi and 55 psi). The test valve shall close at a flow rate of at least<br />
± 25 % of the design closing flow rate indicated in F.1.1 in 30 s or less from the time this flow rate is<br />
achieved, or the test valve fails the test. If the test valve fails, discontinue testing. Record the initial<br />
pressure upstream of the test valve, the differential pressure across the valve closure mechanism and the<br />
flow rate through the valve at closure.<br />
b) Tubing-pressure-type SSCSVs — Decrease the downstream pressure until the test valve closes. The test<br />
valve shall close at a downstream pressure of at least 75 % of the design closing pressure indicated in<br />
F.1.1. The minimum allowable downstream pressure shall be 0,35 MPa (50 psi). The valve shall close in<br />
30 s or less from the time this pressure minimum is achieved, or the valve fails the test. Record the initial<br />
pressure downstream of the test valve and the pressure downstream of the test valve at closure. If the<br />
test valve fails, discontinue testing.<br />
B.16 Class 1 flow test — SSCSV<br />
B.16.1 Record test data as specified in F.1.18.<br />
B.16.2 Circulate water through the system while bypassing the test valve until gas has been displaced from<br />
the system.<br />
B.16.3 Adjust the water circulation rate through the test valve to obtain a flow rate at the value specified in<br />
Table F.3. Record the time at which flow is directed through the test valve and the circulation rate. Circulate<br />
water through the test valve at the specified rate for a minimum of 1 h.<br />
B.16.4 Close the test valve using the liquid closure test procedure (B.15), using water as the test medium<br />
and omitting B.15.1 and B.15.2.<br />
B.17 Class 2 flow test — SSCSV<br />
B.17.1 Record test data as specified in F.1.19.<br />
B.17.2 Prepare a slurry consisting of 150 µm to 180 µm (100 U.S. mesh to 80 U.S. mesh) sand and<br />
viscosified water.<br />
B.17.3 Determine the sand content of the slurry in accordance with the API Manual of Petroleum<br />
Measurement Standards, Chapter 10.4. Adjust the sand content to 2 % ± 0,5 % by adding 150 µm to 180 µm<br />
(100 U.S. mesh to 80 U.S. mesh) sand or by diluting the slurry with water.<br />
B.17.4 Determine the viscosity of the slurry sample with a Marsh funnel viscometer in accordance with<br />
ISO 10414-1. Adjust the viscosity to 70 s ± 5 s by adding a viscosifier or diluting the slurry with water.<br />
NOTE For the purposes of these provisions, API RP 13B1 is equivalent to ISO 10414-1.<br />
B.17.5 The viscosity and sand content requirements specified above shall be met before proceeding.<br />
B.17.6 Adjust the slurry circulation rate to the value specified in Table F.3. Record the slurry circulation rate,<br />
sand content and slurry viscosity. Also, record the time at which the slurry circulation begins.<br />
B.17.7 Circulate slurry through the test valve at the specified rate for a minimum of 1 h, and then close the<br />
test valve using the liquid closure test procedure (see B.15), using slurry as the test medium and omitting<br />
B.15.1 and B.15.2.<br />
B.17.8 At the completion of the circulation period, measure and record the sand content and the slurry<br />
viscosity.<br />
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ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
Annex C<br />
(normative)<br />
Functional testing requirements<br />
C.1 General<br />
To pass the functional test, the SSSV shall successfully complete all steps of the functional-testing procedure<br />
within the limits specified and in the order shown. The manufacturer's test facility shall be equipped with<br />
instrumentation to display and record information required by the test procedure.<br />
Functional testing shall be discontinued if the valve fails to perform within the limits specified for any step. The<br />
basis for discontinuing the test, and any unusual conditions observed at or prior to the time of discontinuance,<br />
shall be noted on the test data form.<br />
Testing may be resumed from the last successfully completed step when it is determined the cause of the<br />
failure is the result of a failure within the test facility.<br />
All pressures are defined as gauge unless otherwise specified and shall be recorded on time-based<br />
equipment.<br />
Prior to any liquid pressure test, purge with test liquid to remove air.<br />
Gas pressure relieving (bleed-down) operations shall be performed per the manufacturer's requirements.<br />
During functional testing of hydraulically operated SSSVs, control line fluid metering may be used to provide a<br />
readable hydraulic control line pressure trace. Refer to Figure F.6 for a characteristic pressure versus time<br />
plot for opening and closing hydraulic control pressures with hydraulic fluid being applied at a metered rate.<br />
The test section shall completely enclose a wireline-retrievable SSSV. Tubing-retrievable SSSVs shall be an<br />
integral part of the test section. The test section shall be rated to at least the rated working pressure of the<br />
SSSV.<br />
C.2 Functional test — SCSSV<br />
C.2.1 Test facility<br />
A typical test facility is shown in Figure F.7 and includes:<br />
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a) test section installed vertically;<br />
b) test section and hydraulic control section pressure measurement devices;<br />
c) pressurized-gas source;<br />
d) hydraulic control pressure system;<br />
e) flow meters;<br />
f) pressurized-water system;<br />
g) time-based recorder to simultaneously record the required data;<br />
h) internal and external drifts.<br />
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ISO 10432:2004(E)<br />
C.2.2 Functional test procedure — SCSSV<br />
All test section pressures shall be measured with calibrated devices and recorded. The procedure shall be as<br />
follows.<br />
a) Record test data as specified in F.1.20.<br />
b) Record the serial number.<br />
c) Place the SCSSV in a fixture capable of retaining and sealing the valve in a vertical position.<br />
d) Open the SCSSV with zero pressure in the test section. Adjust and stabilize the hydraulic control<br />
pressure to the manufacturer's recommended hold-open pressure. Isolate the hydraulic control pressure<br />
from the source. Monitor for a minimum of 5 min. If a loss greater than 5 % of the applied pressure is<br />
detected after stabilization, the SCSSV fails the functional test.<br />
e) Close and open the SCSSV five times with zero pressure in the test section. Record the full-closed and<br />
full-open hydraulic control pressures. Each control pressure shall repeat within ± 5 % of the average<br />
pressure of the five valve cycles as well as falling within the manufacturer's specified control pressure<br />
tolerance. If each pressure is not within these the limits, the SCSSV fails the functional test.<br />
f) Fill the test section with water or another suitable liquid to displace air from the test section, and proceed<br />
as follows.<br />
1) Wireline-retrievable SCSSVs:<br />
Close the SCSSV. Adjust and stabilize the pressure across the entire test section to 150 % of the<br />
rated working pressure (allowable range of 145 % to 155 % of the rated working pressure) for<br />
SCSSVs up to 69 MPa (10 000 psi) rated working pressure. For SCSSVs with rating working<br />
pressures in excess of 69 MPa (10 000 psi), the test pressure shall be the rated working pressure<br />
plus a minimum of 34,5 MPa (5 000 psi). Hold the pressure for a minimum of 5 min. Reduce the<br />
pressure in the test section to zero. Repeat the test once. The SCSSV fails the functional test if<br />
leakage is detected through the hydraulic control port(s).<br />
2) Tubing-retrievable SCSSVs:<br />
Close the SCSSV. Thoroughly dry the test valve exterior. Adjust and stabilize the pressure in the<br />
entire test section to 150 % of the rated working pressure (allowable range of 145 % to 155 % of the<br />
rated working pressure) for SCSSVs up to 69 MPa (10 000 psi) rated working pressure of the SCSSV.<br />
For SCSSVs with rating working pressures in excess of 69 MPa (10 000 psi), the test pressure shall<br />
be the rated working pressure plus a minimum of 34,5 MPa (5 000 psi). Hold the pressure a minimum<br />
of 5 min. Reduce the pressure in the test section to zero. Repeat the test once. The SCSSV fails the<br />
functional test if leakage is detected on the exterior or through the hydraulic control line port(s).<br />
g) Open and close the SCSSV with zero pressure in the test section and record the full-open and full-closed<br />
hydraulic control pressures. Open the SCSSV.<br />
h) Apply pressure of 50 % of the SCSSV's rated working pressure (allowable range of 45 % to 55 % of rated<br />
working pressure) of the test valve to the entire test section. Record the test valve bore pressure (base<br />
pressure).<br />
i) Close and open test valve five times while maintaining the test section pressure recorded in C.2.2 h)<br />
within the specified range.<br />
NOTE<br />
The test section pressure can increase as the valve is opened, and then can decrease as the valve is<br />
closed due to the differential volume of the hydraulic operating piston.<br />
The full-open/full-closed hydraulic control pressures shall be adjusted based on the change in test<br />
section pressure at the time of control pressure measurement. The adjusted control pressure is<br />
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determined by adding/subtracting the actual control pressure with the difference between the base<br />
pressure and the actual test section pressure recorded at the time of each opening/closing pressure<br />
measurement. If the five adjusted hydraulic control pressures do not repeat within ± 10% of their average,<br />
or ± 0,7 MPa (± 100 psi), whichever is greater, or if any body joint leakage (tubing-retrievable only) is<br />
detected, the test valve fails.<br />
j) Adjust and stabilize the test section pressure to 100 % of the rated working pressure (allowable range of<br />
95 % to 105 % of rated working pressure) of the SCSSV. Close the SCSSV. Record the full-closed<br />
hydraulic control pressure. Bleed the hydraulic control pressure to zero.<br />
k) Adjust and stabilize the test section pressure to 100 % of the rated working pressure (allowable range of<br />
95 % to 105 % of rated working pressure) of the SCSSV. Monitor for leakage at hydraulic control line<br />
ports(s) for a minimum of 5 min. If any leakage is detected, the SCSSV fails the functional test.<br />
l) Bleed the pressure above the SCSSV closure mechanism to zero. Adjust and stabilize the pressure below<br />
the closure mechanism to 100 % of the rated working pressure (allowable range of 95 % to 105 % of<br />
rated working pressure) of the SCSSV. Measure liquid leakage for a minimum of 5 min. If the leakage<br />
rate exceeds 10 cm 3 /min, the SCSSV fails the functional test.<br />
m) Remove the liquid from the test section.<br />
n) Open the SCSSV. Record the full-open hydraulic control pressure.<br />
o) Adjust and stabilize the pressure in the entire test section with gas to 1,4 MPa ± 0,07 MPa<br />
(200 psi ± 10 psi). Close the SCSSV. Record the full-closed hydraulic control pressure. Bleed the<br />
hydraulic control pressure to zero.<br />
p) Adjust and stabilize the test section pressure with gas to 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi). Monitor<br />
for gas leakage at the hydraulic control port(s) for a minimum of 5 min. If any leakage is detected, the<br />
SCSSV fails the functional test.<br />
q) Bleed the pressure above the SCSSV's closure mechanism to zero. Adjust and stabilize the pressure<br />
below the SCSSV's closure mechanism to 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) with gas. Measure the<br />
leakage rate for a minimum of 5 min. If the leakage rate exceeds 0,14 m 3 /min (5 scf/min), the SCSSV<br />
fails the functional test.<br />
r) Repeat o) and p) with 8,3 MPa ± 0,41 MPa (1 200 psi ± 60 psi).<br />
s) Bleed all pressures to zero.<br />
t) Open and close the SCSSV two times. Record the full-open and full-closed hydraulic control pressures.<br />
u) Prepare the SCSSV for drift tests. Open the SCSSV, then, proceed as follows.<br />
1) Drift the interior of the SCSSV assembly with the manufacturer's specified drift bar. Pass the drift bar<br />
completely through the test valve.<br />
2) Drift the exterior of wireline-retrievable SCSSVs with the manufacturer's specified drift sleeve. If the<br />
SCSSV fails the drift test, it fails the functional test.<br />
3) Record the drift's unique identifiers and the nominal drift sizes.<br />
v) Special features unique to a manufacturer's SCSSV shall be tested in accordance with the manufacturer's<br />
operating manual. Failure to meet the requirements of these tests fails the SCSSV. These tests can be<br />
incorporated in the existing sequence of functional tests. Such special-feature test procedures, the<br />
sequence and the results shall be fully described in the test report.<br />
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w) If the SCSSV performs within the limits of the functional test, it passes the functional test. Attach all<br />
recorded data to the manufacturer's test form. Certify the test with the appropriate manufacturer's<br />
approval signatures and dates.<br />
C.3 Functional testing — SSCSV<br />
C.3.1 Test facility<br />
A typical test facility is shown in Figure F.8 and includes the following:<br />
a) test section installed vertically;<br />
b) test section pressure measurement devices;<br />
c) pressurized-gas source;<br />
d) flow meters;<br />
e) pressurized-water system;<br />
f) time-based recorder to record the required data simultaneously;<br />
g) drift sleeve.<br />
C.3.2 Functional test procedure — velocity-type SSCSVs<br />
Proceed as follows.<br />
a) Record test data as specified in F.1.21.<br />
b) Record the serial number.<br />
c) Place the SSCSV in a fixture capable of retaining and sealing the valve in a vertical position.<br />
d) Initiate a flow against a minimum back-pressure of 0,35 MPa (50 psi).<br />
e) Check the operation of the recorders for the flow rate, upstream pressure and downstream pressure.<br />
f) Increase flow rate until the SSCSV closes.<br />
g) Record the flow rate and the upstream and downstream pressures at the time of valve closure. If the<br />
closing rate and pressure differential are not within ± 5 % of the manufacturer's specified values, the<br />
SSCSV fails the functional test.<br />
h) Adjust and stabilize the pressure upstream of the SSCSV to 100 % ± 5 % of the rated working pressure.<br />
i) Hold the upstream pressure for a minimum of 5 min and measure the leakage rate. If the leakage rate<br />
exceeds 10 cm 3 /min, the SSCSV fails the functional test.<br />
j) Bleed the pressure from below the SSCSV to a value 0,7 MPa (100 psi) greater than the differential<br />
closing pressure.<br />
k) Adjust the gas pressure to a value 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) greater than the differential<br />
closing pressure.<br />
l) Measure the gas leakage rate for 5 min. If the leakage rate exceeds 0,14 m 3 /min (5 scf/min), the SSCSV<br />
fails the functional test.<br />
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m) Bleed all pressures to zero.<br />
n) Prepare the SSCSV for a drift test. Drift the exterior of a wireline-type SSCSV with the drift sleeve. If the<br />
SSCSV does not pass through the drift sleeve, it fails the functional test. Record the nominal size of the<br />
drift sleeve and the unique identifier.<br />
o) If the SSCSV performs within the limits of the functional test, it has passed the functional test. Attach all<br />
recorded data to the manufacturer's test form. Certify the test with the appropriate manufacturer's<br />
approval signatures and dates.<br />
C.3.3 Functional test procedure — tubing-pressure-type SSCSVs<br />
Proceed as follows:<br />
a) Record test data as specified in F.1.21.<br />
b) Record the serial number.<br />
c) Place the SSCSV in a fixture capable of retaining and sealing the valve in a vertical position.<br />
d) Adjust the flow rate in accordance with Table F.3.<br />
e) Reduce the downstream pressure until the SSCSV closes.<br />
f) Record the flow rate and downstream pressure at the time of valve closure. If the downstream pressure at<br />
closure is not within ± 5 % of the manufacturer's specified pressure or 0,7 MPa (100 psi), whichever is<br />
larger, the SSCSV fails the functional test.<br />
g) Bleed the downstream pressure to zero.<br />
h) Adjust and stabilize the pressure upstream of the SSCSV to 100 % ± 5 % of the rated working pressure of<br />
the SSCSV.<br />
i) Hold the upstream pressure for a minimum of 5 min and measure the leakage rate. If the leakage rate<br />
exceeds 10 cm 3 /min, the SSCSV fails the functional test.<br />
j) Bleed the upstream pressure from the SSCSV to a value 0,7 MPa (100 psi) greater than the closing<br />
pressure.<br />
k) Adjust the upstream pressure with gas to a value 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) greater than the<br />
closing pressure.<br />
l) Measure the gas leakage rate for 5 min. If the leakage rate exceeds 0,14 m 3 /min (5 scf/min), the SSCSV<br />
fails the functional test.<br />
m) Bleed all pressures to zero.<br />
n) Prepare the SSCSV for a drift test. Drift the exterior of wireline-type SSCSVs with a drift sleeve. If the<br />
SSCSV does not pass through the drift sleeve, it fails the functional test.<br />
o) If the SSCSV performs within the limits of the functional test, it has passed the test. Attach all recorded<br />
data to the manufacturer's test form. Certify the test with the appropriate manufacturer's approval<br />
signatures and dates.<br />
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ISO 10432:2004(E)<br />
C.4 Functional testing — Other types of SSSV<br />
The following shall apply:<br />
a) The manufacturer shall document the functional-test procedure and record test data.<br />
b) The apparatus and test procedure for a specific SSSV not included in previous subclauses shall be as<br />
specified by the manufacturer.<br />
c) The manufacturer shall be responsible for assuring that the test procedures are not less stringent than<br />
those in this International Standard.<br />
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API Specification 14A / ISO 10432<br />
Annex D<br />
(informative)<br />
Optional requirement for closure mechanism minimal leakage<br />
D.1 General<br />
Minimal leakage rate applies only to the functional test. If a minimal leakage requirement is specifically<br />
requested by user/purchaser, the supplier shall adhere to D.2 and D.3.<br />
NOTE<br />
These test requirements are optional and do not mandate minimal leakage requirements for all SSSVs.<br />
D.2 Gas leakage test requirements<br />
If the leakage rate exceeds 14,2 dm 3 /min (0,5 scfm), the SSSV fails the functional test.<br />
D.3 Liquid leakage test requirements<br />
If the leakage rate exceeds 1 cm 3 /min (0,034 fl oz/min), the SSSV fails the functional test.<br />
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API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
Annex E<br />
(informative)<br />
Operating envelope<br />
E.1 General<br />
Reference ISO 13679 or API Bull 5C3, API Bull 5C5 or other nationally or internationally accepted reference<br />
standards. Specifically note ISO 13679 or API Bull 5C5 procedures and test requirements for combined load<br />
testing.<br />
E.2 Envelope documentation<br />
If specified by the user/purchaser, an operating envelope shall be supplied for tubing-retrievable subsurface<br />
safety valves to illustrate the combined effects of pressure, temperature, and axial loads, as various well<br />
completion schemes dictate that information be available to an user/purchaser during completion/production<br />
operations. The operating envelope may be based upon test data and/or calculated data.<br />
An example envelope is illustrated below. The area within the boundaries defines the operating envelope. The<br />
lines forming the boundary of the envelope are defined by the various failure modes of the SCSSV.<br />
Key<br />
X axial load<br />
Y pressure<br />
a<br />
b<br />
c<br />
d<br />
Burst only (+VME).<br />
Collapse only (−VME).<br />
Compression (−VME).<br />
Tension (+VME).<br />
Figure E.1 — Operating envelope example<br />
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E.3 Envelope requirements<br />
Operating envelopes shall meet the criteria below.<br />
⎯<br />
⎯<br />
⎯<br />
The boundary lines of the envelope represent the manufacturer's maximum ratings.<br />
More than one graph may be displayed on the envelope if a legend is included for explanation. For<br />
example, calculated versus tested operating envelope data.<br />
The product(s) covered by the envelope shall be specified on the envelope.<br />
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API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
Annex F<br />
(normative)<br />
Data requirements, figures/schematics, and tables<br />
F.1 Data requirements<br />
F.1.1 Validation test application — SSSV (reference 6.5.2)<br />
a) General requirements are as follows:<br />
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1) identification of test agency (company/facility name, location/address, pertinent department, etc.);<br />
2) identification of product manufacturer (company name, location/address, pertinent department,<br />
contact name & phone numbers, etc.);<br />
3) date of validation test and date of report;<br />
4) validation test number (provided by test facility);<br />
5) if retest, reference to previous test number;<br />
6) the test application shall include a statement verifying a successful proof test to the anticipated test<br />
loads of the SSSV and all hardware supplied for the test.<br />
b) The equipment to be tested shall be identified as follows:<br />
1) equipment type: SCSSV, SSCSV (surface controlled vs. subsurface controlled, etc.);<br />
2) model designation or other identification by manufacturer;<br />
3) product number with unique serial number;<br />
4) nominal tubing size;<br />
5) rated working pressure rating;<br />
6) test section length;<br />
7) for SCSSV equipment:<br />
i) minimum specified ID,<br />
ii)<br />
maximum hydraulic control line pressure (greater than valve bore pressure),<br />
iii) maximum unequalized opening pressure;<br />
8) for SSCSV equipment:<br />
i) closing parameters (fluid velocity, pressure, design closing flow rate, etc. as appropriate),<br />
ii)<br />
tubing pressure: design closing pressure.<br />
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c) The following procedures and special requirements shall be stated:<br />
1) Class 1 or 2 service designation;<br />
2) Non-specified equipment or procedures required for testing;<br />
3) All requested variation(s) to the test agency's testing procedures shall be accurately defined, as well<br />
as the specific point in the testing procedure where the testing variation(s) are to be implemented.<br />
The specific procedures of the requested variation(s) and a document that verifies that variations to<br />
the requirements are not less stringent than those of the referenced standard are required as a<br />
component of the application.<br />
4) If new equipment, specific details of methods and/or practices that may be required.<br />
d) Space shall be provided for the following information from the test agency:<br />
1) testing schedule (month/day/year);<br />
2) test location;<br />
3) applicant notified (month/day/year).<br />
F.1.2 Gas flow test — SCSSV (reference B.3)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) date (month/day/year);<br />
c) test start time; test stop time;<br />
d) data to be collected/recorded for each flow test shall be as follows:<br />
1) hydraulic opening pressure at zero bore pressure,<br />
2) hydraulic closing pressure at zero bore pressure,<br />
3) hydraulic opening pressure at 13,8 MPa to 17,2 MPa (2 000 psi to 2 500 psi) bore pressure,<br />
4) closure data:<br />
i) gas flow rate,<br />
ii)<br />
full-closed hydraulic control pressure,<br />
iii) time to close,<br />
5) nitrogen leakage data:<br />
i) test pressure,<br />
ii)<br />
leakage rate,<br />
iii) body joint leakage detected? (yes or no);<br />
e) test passed? (yes or no);<br />
f) conducted by: (printed name and signature), date: (month/day/year).<br />
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F.1.3 Drift test — SCSSV (reference B.4)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) drift information:<br />
1) minimum inside diameter or maximum outside diameter of test valve (specify ID or OD),<br />
2) drift bar outside diameter or drift sleeve inside diameter (specify ID or OD),<br />
3) drift length,<br />
4) unique identifier of drift bar or sleeve;<br />
c) for each drift test, record the following:<br />
1) date of test (month/day/year),<br />
2) full-open hydraulic control pressure (five times),<br />
3) full-closed hydraulic control pressure (five times),<br />
4) drift pass? (yes or no);<br />
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d) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.4 Initial opening and closing test — SCSSV (references B.2.2.2 and B.2.2.4)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) date (month/day/year);<br />
d) test start time; test stop time;<br />
e) open and close at zero valve bore pressure:<br />
1) full-open hydraulic control pressure (measured),<br />
2) full-closed hydraulic control pressure (measured);<br />
f) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.5 Liquid leakage test — SSSV (reference B.5)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) for each iteration (B.2.2.5, B.2.2.13, and B.2.3.5) of the liquid leakage test, record the following:<br />
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1) identification of the applicable test step being performed (note class of service as well),<br />
2) date of test (month/day/year),<br />
3) valve bore test pressure (nominal 100 % of rated working pressure),<br />
4) time at which test pressure is applied,<br />
5) time at start of leakage test,<br />
6) time at end of leakage test,<br />
7) average leakage rate at test pressure (100 % of rated working pressure),<br />
8) body leakage detected (TRSV only)? (yes or no),<br />
9) test step passed? (yes or no);<br />
d) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.6 Unequalized opening test — SCSSV (reference B.6)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) date (month/day/year);<br />
d) rated working pressure of SCSSV being tested;<br />
e) manufacturer's maximum recommended unequalized opening pressure (from operating manual);<br />
f) for each unequalized opening test, record the following:<br />
1) test start time; test completion time,<br />
2) valve bore upstream test pressure (measured),<br />
3) equalizing test pressure (measured),<br />
4) full-open hydraulic control pressure (measured);<br />
g) Test passed? (yes or no);<br />
h) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.7 Operating pressure test — SCSSV (reference B.7)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) for each iteration (B.2.2.7, B.2.2.10, B.2.2.12, B.2.3.2, and B.2.3.4) of the operating pressure test, record<br />
the following:<br />
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1) date (month/day/year),<br />
2) initial SCSSV valve bore pressure (base pressure) at 25 % of working pressure,<br />
3) full-open hydraulic control pressure (and actual test section pressure),<br />
4) full-closed hydraulic control pressure (and actual test section pressure),<br />
5) record repeated cycle results as specified by the requirement in B.7,<br />
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6) repeat above at 75 % of working pressure;<br />
d) calculate the following values:<br />
1) adjusted hydraulic control pressure — full-closed,<br />
2) average of adjusted hydraulic control pressure — full-closed,<br />
3) adjusted hydraulic control pressure — full-open,<br />
4) average of adjusted hydraulic control pressure — full-open;<br />
e) body leakage detected (TRSV only)? (yes or no);<br />
f) test passed? (yes or no);<br />
g) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.8 Propane test — SSSV (reference B.8)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) date (month/day/year);<br />
d) for each of the open/close cycles at zero test valve bore pressure, record the following:<br />
1) full-closed hydraulic control pressure,<br />
2) full-open hydraulic control pressure;<br />
e) calculate the following values for the set of cycles just completed:<br />
1) average adjusted hydraulic control pressure — full-closed; same plus 10 %; same minus 10 %,<br />
2) average adjusted hydraulic control pressure — full-open; same plus 10 %; same minus 10 %;<br />
f) for each of the open/close cycles at 2,8 MPa (400 psi) test valve nominal bore pressure, record the<br />
following:<br />
1) time at valve closure,<br />
2) full-closed hydraulic control pressure,<br />
3) time at valve opening,<br />
4) full-open hydraulic control pressure;<br />
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g) calculate the following values for the set of cycles just completed:<br />
1) average adjusted hydraulic control pressure — full-closed; same plus 10 %; same minus 10 %;<br />
2) average adjusted hydraulic control pressure — full-open; same plus 10 %; same minus 10 %.<br />
h) for (each) propane soak period. record the following:<br />
1) time at start of soak period,<br />
2) time at end of soak period,<br />
3) valve bore pressure at end of soak period;<br />
i) record the last full-closed hydraulic control pressure at the end of the propane test.<br />
j) Test passed? (yes or no);<br />
k) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.9 Nitrogen leakage test — SSSV (reference B.9)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) for each iteration (B.2.2.9, B.2.2.12, B.2.3.1, and B.2.3.4) of the nitrogen leakage test, record the<br />
following:<br />
1) date (month/day/year),<br />
2) SCSSV bore pressure [1,33 MPa to 1,47 MPa (190 psi to 210 psi)],<br />
3) time at start of waiting period,<br />
4) time at completion of waiting period,<br />
5) measured gas leakage rate,<br />
6) body leakage detected (TRSV only)? (yes or no),<br />
7) SCSSV bore pressure [20 % to 30 % of rated working pressure (RWP)],<br />
8) full-open hydraulic control pressure,<br />
9) time at start of waiting period,<br />
10) time at completion of waiting period,<br />
11) measured gas leakage rate,<br />
12) body leakage detected (TRSV only)? (yes or no),<br />
13) test passed? (yes or no);<br />
d) conducted by: (printed name and signature), date: (month/day/year).<br />
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ISO 10432:2004(E)<br />
F.1.10 Class 1 flow test — SCSSV (reference B.10)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) for each iteration (B.2.2.11 and B.2.2.12) of the Class 1 flow test, record the following:<br />
1) date of test (month/day/year),<br />
2) for each circulation flow rate record the following:<br />
i) time at start of circulation through test valve,<br />
ii)<br />
time at valve closure,<br />
iii) water flow rate immediately before valve closure,<br />
iv) full-closed hydraulic control pressure,<br />
v) flow 15 s after hydraulic control pressure reaches zero,<br />
vi) time to close,<br />
vii) full-open hydraulic control pressure;<br />
d) test passed? (yes or no);<br />
e) conducted by: (printed name and signature), date (month/day/year).<br />
F.1.11 Controlled temperature test — SCSSV (reference B.11)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) SCSSV stabilized test temperature;<br />
d) For each iteration (B.11.4, B.11.7, and B.11.9) of the controlled temperature test, record the following:<br />
1) date (month/day/year),<br />
2) initial SCSSV valve bore pressure (base pressure) at 25 % of working pressure at 38 °C (100 °F) and<br />
82 °C (180 °F),<br />
3) full-open hydraulic control pressure (and actual test section pressure),<br />
4) full-closed hydraulic control pressure (and actual test section pressure),<br />
5) record repeated cycle results as specified by the requirements in B.11.4,<br />
6) repeat above at 75 % of working pressure;<br />
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e) Calculate the following values:<br />
1) adjusted hydraulic control pressure — fully-closed,<br />
2) average of adjusted hydraulic control pressure — fully-closed,<br />
3) adjusted hydraulic control pressure — fully-open,<br />
4) average of adjusted hydraulic control pressure — fully-open;<br />
f) For each control line leakage test (at specified valve temperature and pressure), record the following:<br />
1) time at start of waiting period,<br />
2) time at completion of waiting period,<br />
3) leak detected? (yes or no),<br />
4) body leakage detected (TRSV only)? (yes or no);<br />
g) For each closure mechanism leakage test (at specified valve temperature and pressure below the closure<br />
mechanism), record the following:<br />
1) test temperature,<br />
2) time at which the bore pressure above the closure mechanism is reduced to zero,<br />
3) valve bore pressure below the closure mechanism,<br />
4) time at start of waiting period,<br />
5) time at completion of waiting period,<br />
6) leakage rate,<br />
h) Test passed? (yes or no);<br />
i) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.12 Class 2 flow test — SCSSV (reference B.12)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) For each iteration (B.2.3.3 and B.2.3.4) of the Class 2 flow test, record the following:<br />
1) date of test (month/day/year),<br />
2) time at start of slurry circulation through valve,<br />
3) flow rate at start of circulation period,<br />
4) sand concentration (%) at start of circulation period,<br />
5) slurry viscosity at start of circulation period,<br />
6) time at valve closure (against slurry flow),<br />
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ISO 10432:2004(E)<br />
7) slurry flow rate,<br />
8) full-closed hydraulic control pressure,<br />
9) flow 15 s after hydraulic control pressure reaches zero,<br />
10) time to close,<br />
11) sand concentration (%)at completion of circulation period,<br />
12) slurry viscosity at completion of circulation period,<br />
13) test passed? (yes or no);<br />
d) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.13 Validation test summary — SSSV (references A.1, B.2.3.8 and B.13.15)<br />
The following shall be recorded:<br />
a) identification of test agency (company/facility name, location/address, pertinent department, etc.);<br />
b) identification of product manufacturer (company name, location/address, pertinent department, contact<br />
name & phone numbers, etc.);<br />
c) date of validation test and date of report;<br />
d) validation test number (provided by test facility);<br />
e) equipment type: SCSSV, SSCSV (surface controlled vs. subsurface controlled, etc.);<br />
f) model designation or other identification by manufacturer;<br />
g) product number with unique serial number;<br />
h) nominal tubing size;<br />
i) rated working pressure;<br />
j) service class tested (1 or 2);<br />
k) service class passed (1 or 2);<br />
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l) if valve failed the test, step at which the failure occurred and the reason for failure;<br />
m) remarks (describing any non-specified equipment or procedures requested by valve manufacturer,<br />
unusual conditions observed during test, etc.);<br />
n) test approved by: (test agency approval authority), date: (month/day/year).<br />
F.1.14 Gas closure test — SSCSV (reference B.14)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
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API Specification 14A / ISO 10432<br />
c) test start time;<br />
d) test completion time;<br />
e) date (month/day/year);<br />
f) for velocity-type SSCSVs:<br />
1) initial test valve upstream pressure,<br />
2) closing flow rate (gas),<br />
3) differential closing pressure,<br />
4) calculate maximum closing rate,<br />
5) calculate minimum closing rate;<br />
g) for tubing-pressure-type SSCSVs:<br />
1) initial test valve downstream pressure,<br />
2) downstream closing pressure,<br />
3) design closing pressure,<br />
4) calculate maximum closing rate,<br />
5) calculate minimum closing rate;<br />
h) nitrogen leakage data:<br />
1) test valve bore pressure,<br />
2) leakage rate;<br />
i) test passed? (yes or no);<br />
j) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.15 Liquid closure test — SSCSV (reference B.15)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) number;<br />
c) test start time;<br />
d) test completion time;<br />
e) date (month/day/year);<br />
f) for velocity-type SSCSVs:<br />
1) initial test valve downstream pressure,<br />
2) closing flow rate (water),<br />
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ISO 10432:2004(E)<br />
3) differential closing pressure,<br />
4) design closing flow rate (liquid),<br />
5) maximum closing rate: 125 % × design closing rate (liquid),<br />
6) minimum closing rate: 75 % × design closing rate (liquid);<br />
g) for tubing-pressure-type SSCSVs:<br />
1) initial test valve downstream pressure,<br />
2) downstream closing pressure,<br />
3) maximum closing rate: 125 % × design closing rate (liquid),<br />
4) minimum closing rate: 75 % × design closing rate (liquid);<br />
h) test passed? (yes or no);<br />
i) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.16 Propane test — SSCSV (reference B.13.5)<br />
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The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) propane soak period:<br />
1) date,<br />
2) 2 h soak period:<br />
i) start,<br />
ii)<br />
stop;<br />
3) valve bore pressure at end of 2 h soak period;<br />
d) closure after propane soak:<br />
1) test start time,<br />
2) test completion time,<br />
3) date (month/day/year);<br />
e) for velocity-type SSCSVs:<br />
1) initial test valve downstream pressure,<br />
2) closing flow rate (water):<br />
i) + 15 % of the closing flow rate recorded in F.1.15 f) 2),<br />
ii) − 15 % of the closing flow rate recorded in F.1.15 f) 2);<br />
3) differential closing pressure;<br />
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f) for tubing-pressure-type SSCSVs:<br />
1) initial test valve downstream pressure,<br />
2) downstream closing pressure:<br />
i) + 15 % of the downstream closing pressure recorded in F.1.15 g) 2),<br />
ii) − 15 % of the downstream closing pressure recorded in F.1.15 g) 2);<br />
g) test passed? (yes or no);<br />
h) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.17 Nitrogen leakage — SSCSV (reference B.13.6)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) for each iteration of the SSCSV nitrogen leakage test (reference B.13.6 and B.13.8):<br />
1) date (month/day/year),<br />
2) valve bore test pressure [1,33 MPa to 1,47 MPa (190 psi to 210 psi)],<br />
3) time at start of waiting period,<br />
4) time at completion of waiting period,<br />
5) measured gas leakage rate,<br />
6) valve bore test pressure (20 % to 30 % RWP),<br />
7) time at start of waiting period,<br />
8) time at completion of waiting period,<br />
9) measured gas leakage rate,<br />
10) test passed? (yes or no);<br />
d) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.18 Class 1 flow test — SSCSV (reference B.16)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) identification;<br />
c) for velocity-type SSCSVs:<br />
1) + 15 % of closing flow rate recorded in F.1.15 f) 2),<br />
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ISO 10432:2004(E)<br />
2) − 15 % of closing flow rate recorded in F.1.15 f) 2);<br />
d) For tubing-pressure-type SSCSVs:<br />
1) + 15 % of downstream closing pressure recorded in F.1.15 g) 2),<br />
2) − 15 % of downstream closing pressure recorded in F.1.15 g) 2);<br />
e) For each iteration of the SSCSV Class 1 flow test (reference B.13.7 and B.13.8), record the following:<br />
1) date of test (month/day/year),<br />
2) for each circulation flow rate record the following:<br />
i) time at start of circulation through test valve,<br />
ii)<br />
flow rate at start of circulation period,<br />
iii) time at valve closure;<br />
3) for velocity-type SSCSVs:<br />
i) initial downstream pressure,<br />
ii)<br />
water flow rate at closure,<br />
iii) differential pressure across valve at closure;<br />
4) for tubing-pressure-type SSCSVs:<br />
i) initial downstream pressure,<br />
ii)<br />
downstream pressure at closure;<br />
5) test passed? (yes or no).<br />
f) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.19 Class 2 flow test — SSCSV (reference B.17)<br />
The following shall be recorded:<br />
a) validation test number;<br />
b) test stand (or apparatus) number;<br />
c) for velocity-type SSCSVs:<br />
1) + 15 % of closing flow rate recorded in F.1.15 f) 2),<br />
2) − 15 % of closing flow rate recorded inF.1.15 f) 2);<br />
d) for tubing-pressure-type SSCSVs:<br />
1) + 15 % of downstream closing pressure recorded in F.1.15 g) 2),<br />
2) − 15 % of downstream closing pressure recorded in F.1.15 g) 2);<br />
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e) For each iteration of the SSCSV Class 1 flow test (reference B.13.11 and B.13.12), record the following:<br />
1) date of test (month/day/year),<br />
2) For each circulation flow rate record the following:<br />
i) time at start of circulation through test valve,<br />
ii)<br />
flow rate at start of circulation period,<br />
iii) sand concentration (%) at start of circulation period,<br />
iv) slurry viscosity at start of circulation period (Marsh seconds),<br />
v) time at valve closure (against slurry flow);<br />
3) for velocity-type SSCSVs:<br />
i) initial downstream pressure,<br />
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ii)<br />
slurry flow rate at closure,<br />
iii) differential pressure across valve at closure;<br />
4) for tubing-pressure-type SSCSVs:<br />
i) initial downstream pressure,<br />
ii)<br />
downstream pressure at closure,<br />
iii) sand concentration (%) at completion,<br />
iv) slurry viscosity at completion of circulation period;<br />
5) test passed? (yes or no);<br />
f) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.20 Functional test documentation — SCSSV (reference C.2)<br />
The following shall be recorded:<br />
a) valve manufacturer;<br />
b) equipment name;<br />
c) SSSV type and size;<br />
d) product/material number and unique serial number;<br />
e) working pressure rating;<br />
f) hydrostatic control pressure test:<br />
1) start time at pressure,<br />
2) end time at pressure,<br />
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ISO 10432:2004(E)<br />
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3) beginning control pressure,<br />
4) ending control pressure,<br />
5) calculate pressure loss over minimum of 5 min,<br />
6) test passed? (yes or no);<br />
g) control pressure repeatability:<br />
1) at zero valve bore pressure,<br />
2) full-open hydraulic control pressure,<br />
3) full-closed hydraulic control pressure,<br />
4) repeat cycle five times,<br />
5) calculate average of five cycles;<br />
6) test passed? (yes or no);<br />
h) hydrostatic test (for each iteration):<br />
1) start time at pressure,<br />
2) end time at pressure,<br />
3) beginning section pressure,<br />
4) ending section pressure,<br />
5) leakage within 5 min? (yes or no),<br />
6) test passed? (yes or no);<br />
i) record full-open/full-closed pressures;<br />
j) SCSSV operating pressure test:<br />
1) for each iteration of the operating pressure test, record the following:<br />
i) initial SCSSV valve bore pressure (base pressure) at 50 % of working pressure,<br />
ii)<br />
full open hydraulic control pressure (and actual test section pressure),<br />
iii) full-closed hydraulic control pressure (and actual test section pressure),<br />
iv) record repeated cycle results as specified by the requirements of C.2.2 h);<br />
2) calculate the following values:<br />
i) adjusted hydraulic control pressure — fully-closed,<br />
ii)<br />
average of adjusted hydraulic control pressure — fully-closed,<br />
iii) adjusted hydraulic control pressure — fully-open,<br />
iv) average of adjusted hydraulic control pressure — fully-open;<br />
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3) body joint leakage detected (TRSV only)? (yes or no);<br />
k) record full-open/full-closed hydraulic control pressure at 100 % test section pressure;<br />
l) with 100 % test section pressure and zero hydraulic control pressure:<br />
1) control port leakage within 5 min? (yes or no),<br />
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2) test passed? (yes or no);<br />
m) closure mechanism leakage test at 100 % pressure below closure mechanism:<br />
1) measured leakage in cm 3 /minute within 5 min? (yes or no),<br />
2) test passed? (yes or no);<br />
n) record full-open hydraulic control pressure;<br />
o) with 1,4 MPa (200 psi) gas pressure in test section:<br />
1) record full-closed hydraulic pressure,<br />
2) control port leakage within 5 min? (yes or no),<br />
3) test passed? (yes or no);<br />
p) with zero test section pressure and 1,4 MPa (200 psi) gas pressure below closure mechanism:<br />
1) measured leakage in m 3 /min within 5 min? (yes or no),<br />
2) test passed? (yes or no);<br />
q) results of repeat of o) and p) at 8,3 MPa (1 200 psi);<br />
r) record full-open/full-closed hydraulic control pressures two times;<br />
s) internal/external drift test. test passed? (yes or no);<br />
t) special features test results. test passed? (yes or no);<br />
u) test date;<br />
v) performed by: (printed name and signature), date: (month/day/year).<br />
F.1.21 Functional test documentation — SSCSV (reference C.3)<br />
The following shall be recorded:<br />
a) valve manufacturer;<br />
b) equipment name;<br />
c) SSSV type and size;<br />
d) SSSV catalogue/material number and unique serial number;<br />
e) safety valve lock, serial number, and size (as applicable);<br />
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ISO 10432:2004(E)<br />
f) working pressure rating;<br />
g) for velocity-type SSCSVs:<br />
1) initial flow rate,<br />
2) initial upstream pressure,<br />
3) initial downstream pressure,<br />
4) flow rate at moment of SSCSV closing,<br />
5) upstream pressure at moment of SSCSV closing,<br />
6) downstream pressure at moment of SSCSV closing,<br />
7) liquid leakage rate over period of 5 min with upstream liquid pressure equal to 100 % SSCSV rated<br />
working pressure,<br />
8) gas leakage rate over period of 5 min with upstream gas pressure equal to 1,4 MPa (200 psi),<br />
9) drift test results (reference B.4),<br />
10) test passed? (yes or no);<br />
h) for tubing-pressure-type SSCSVs:<br />
1) liquid flow rate as specified in Table F.3,<br />
2) flow rate at moment of SSCSV closing,<br />
3) downstream pressure at moment of SSCSV closing,<br />
4) liquid leakage rate over period of 5 min with upstream liquid pressure equal to 100 % SSCSV rated<br />
working pressure,<br />
5) gas leakage rate over period of 5 min with upstream gas pressure equal to 1,4 MPa (200 psi),<br />
6) drift test results (reference B.4),<br />
7) test passed? (yes or no);<br />
i) conducted by: (printed name and signature), date: (month/day/year).<br />
F.1.22 Shipping report — SSSV (reference 7.9.2.1)<br />
The following shall be recorded:<br />
a) manufacturer's data:<br />
1) manufacturer's name and manufacturing address,<br />
2) product/material number,<br />
3) equipment name,<br />
4) serial number,<br />
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5) size,<br />
6) class of service;<br />
b) SSSV data:<br />
1) pressure rating,<br />
2) temperature rating, maximum,<br />
3) temperature rating, minimum,<br />
4) validation test agency,<br />
5) validation test number,<br />
6) date of report (month/day/year),<br />
7) tested to International Standard ISO 10432:2004;<br />
c) SSSV function test summary:<br />
1) opening pressure with zero pressure in test section: maximum and minimum,<br />
2) closing pressure with zero pressure in test section: maximum and minimum,<br />
3) performed by: (printed name and signature), date: (month/day/year);<br />
d) inspected by: (printed name and signature), date: (month/day/year).<br />
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ISO 10432:2004(E)<br />
F.2 Figures/schematics<br />
Key<br />
1 gas supply 7 bleed valve<br />
2 pressure measurement device 8 leakage flow meter<br />
3 gas reservoir 9 flow control valve<br />
4 shut-off valve 10 vent<br />
5 flow meter 11 SSSV test section<br />
6 equalizing line 12 hydraulic pressure source (for SCSSVs only)<br />
Figure F.1 — Example schematic of gas flow facility<br />
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API Specification 14A / ISO 10432<br />
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Key<br />
1 hydraulic oil 11 see Figure F.3<br />
2 air supply 12 by-pass valve<br />
3 hydraulic pressure source 13 flow meter<br />
4 hydraulic control system 14 recorder<br />
5 high-pressure water system 15 relief valve<br />
6 nitrogen supply 16 pump<br />
7 propane supply 17 drain valve<br />
8 manifold valves 18 water supply<br />
9 choke valve 19 liquid supply tank<br />
10 test section<br />
Figure F.2 — Example schematic of liquid test facility<br />
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Key<br />
1 gas/liquid separator 10 upstream isolation valve<br />
2 drain 11 SSSV<br />
3 nitrogen flow meter 12 downstream isolation valve<br />
4 shut-off valve 13 balance valve<br />
5 test section 14 differential pressure measuring device<br />
6 hydraulic control line bleed valve 15 pressure-measuring device<br />
7 metering valve 16 high-pressure water manifold valve<br />
8 hydraulic control valve 17 propane manifold valve<br />
9 bleed valve 18 nitrogen manifold valve<br />
Figure F.3 — Example detail of liquid test facility<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
69<br />
© ISO 2004 – All rights reserved 69<br />
Licensee=Qatar Petroleum/5943408001
ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
Key<br />
1 hydraulic oil 8 pressure-measuring device<br />
2 air supply 9 test section<br />
3 hydraulic pressure source (for SCSSVs only) 10 thermocouple<br />
4 shut-off valve 11 heating chamber<br />
5 vent valve 12 nitrogen pressure intensifier<br />
6 nitrogen flow meter 13 nitrogen pressure source<br />
7 recorder 14 relief valve<br />
Figure F.4 — Example schematic of controlled-temperature test facility<br />
70<br />
70 © ISO 2004 – All rights reserved<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
Licensee=Qatar Petroleum/5943408001
API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
Key<br />
1 high-pressure propane tank 6 liquid shut-off valve<br />
2 nitrogen tank 7 low-pressure propane storage tank<br />
3 shut-off valve 8 SSSV<br />
4 relief valve 9 test section<br />
5 vent valve 10 pressure-measuring device<br />
Figure F.5 — Example schematic of propane test facility<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
71<br />
© ISO 2004 – All rights reserved 71<br />
Licensee=Qatar Petroleum/5943408001
ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
Key<br />
X hydraulic pressure, increasing to the right<br />
Y time, with hydraulic control pressure applied or released at a metered rate, increasing upwards<br />
1 SCSSV becomes fully open<br />
2 hydraulic system pressure<br />
3 SCSSV becomes fully closed<br />
Figure F.6 — Example of characteristic hydraulic control pressure curve for SCSSVs<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
72<br />
72 © ISO 2004 – All rights reserved<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
Licensee=Qatar Petroleum/5943408001
API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
Key<br />
1 hydraulic oil 9 bleed valve<br />
2 air supply 10 equalizing line<br />
3 hydraulic control system 11 SSSV<br />
4 pressure-measuring device 12 test section<br />
5 recorder 13 balance valve<br />
6 hydraulic control valve 14 test liquid source<br />
7 hydraulic control line bleed valve 15 test gas source<br />
8 nitrogen flow meter<br />
Figure F.7 — Example schematic of functional-test facility for hydraulically actuated SSSVs<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
73<br />
© ISO 2004 – All rights reserved 73<br />
Licensee=Qatar Petroleum/5943408001
ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
Key<br />
1 water or high-pressure gas source<br />
2 flow control valve<br />
3 test gas source<br />
4 air supply<br />
5 test liquid source<br />
6 pressure-measuring device<br />
7 recorder<br />
8 nitrogen flow meter<br />
9<br />
10<br />
11<br />
12<br />
13<br />
14<br />
15<br />
16<br />
downstream pressure-measuring<br />
device<br />
strip-chart recorder<br />
flow meter<br />
downstream isolation valve<br />
bleed valve<br />
equalizing line<br />
SSSV<br />
test section<br />
17<br />
18<br />
19<br />
20<br />
21<br />
22<br />
balance valve<br />
connector<br />
upstream pressure-measuring<br />
device<br />
upstream isolation valve<br />
downstream pressure regulator<br />
water or gas return<br />
Figure F.8 — Example schematic of functional-test facility for velocity- and tubing-pressure-activated<br />
SSSVs<br />
74<br />
74 © ISO 2004 – All rights reserved<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
Licensee=Qatar Petroleum/5943408001
API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
F.3 Tables<br />
Table F.1 — SCSSV gas flow rates (see B.3) a<br />
Nominal<br />
tubing or<br />
casing size<br />
mm (in)<br />
Test No. 1<br />
Flow rate<br />
m 3 /d × 10 6 (scf/d × 10 6 )<br />
Gas flow rate and control line resistances for each valve closure test<br />
Low resistance<br />
Test No. 2<br />
Flow rate<br />
m 3 /d × 10 6 (scf/d × 10 6 )<br />
Test No. 3<br />
Flow rate<br />
m 3 /d × 10 6 (scf/d × 10 6 )<br />
High resistance<br />
Test No. 4<br />
Flow rate<br />
m 3 /d × 10 6 (scf/d × 10 6 )<br />
60,3 (2 3/8) 0,14 (5,1) 0,22 (7,7) 0,07 (2,6) 0,14 (5,1)<br />
73,0 (2 7/8) 0,23 (8,0) 0,34 (12,0) 0,11 (4,0) 0,23 (8,0)<br />
88,9 (3 1/2) 0,33 (11,5) 0,49 (17,3) 0,16 (5,8) 0,33 (11,5)<br />
101,6 (4) 0,44 (15,7) 0,67 (23,6) 0,22 (7,9) 0,44 (15,7)<br />
114,3 (4 1/2) 0,58 (20,5) 0,87 (30,8) 0,29 (10,3) 0,58 (20,5)<br />
127,0 (5) 0,73 (25,9) 1,10 (38,9) 0,37 (13,0) 0,73 (25,9)<br />
139,7 (5 1/2) 0,91 (32,0) 1,36 (48,0) 0,45 (16,0) 0,91 (32,0)<br />
165,1 (6 1/2) 1,30 (46,1) 1,96 (69,2) 0,65 (23,1) 1,30 (46,1)<br />
177,8 (7) 1,79 (63,1) 2,68 (94,7) 0,89 (31,6) 1,79 (63,1)<br />
a<br />
See B.3.1 and B.3.2 for information on the basis of this table, and requirements for its application.<br />
Nominal<br />
tubing or<br />
casing size<br />
Table F.2 — SCSSV liquid flow rates (see B.10 and B.12)<br />
Circulation rate<br />
m 3 /d (B/D)<br />
(± 10 %)<br />
Class 1 Class 2<br />
mm (in) Test rate No. 1 Test rate No. 2 Test rate No. 3<br />
60,3 (2 3/8)<br />
79 (500)<br />
159 (1 000)<br />
238 (1 500)<br />
79 (500)<br />
73,0 (2 7/8)<br />
124 (780)<br />
248 (1 560)<br />
372 (2 340)<br />
124 (780)<br />
88,9 (3 1/2)<br />
178 (1 120)<br />
356 (2 240)<br />
534 (3 360)<br />
178 (1 120)<br />
101,6 (4)<br />
238 (1 500)<br />
477 (3 000)<br />
715 (4 500)<br />
238 (1 500)<br />
114,3 (4 1/2)<br />
305 (1 920)<br />
610 (3 840)<br />
915 (5 760)<br />
305 (1 920)<br />
127,0 (5)<br />
386 (2 430)<br />
772 (4 860)<br />
1 159 (7 290)<br />
386 (2 430)<br />
139,7 (5 1/2)<br />
477 (3 000)<br />
954 (6 000)<br />
1 431 (9 000)<br />
477 (3 000)<br />
165,1 (6 1/2)<br />
686 (4 320)<br />
1 373 (8 640)<br />
2 060 (12 960)<br />
686 (4 320)<br />
177,8 (7)<br />
935 (5 880)<br />
1 869 (11 760)<br />
2 804 (17 640)<br />
935 (5 880)<br />
The manufacturer establishing sizes not covered by this table may interpolate or extrapolate,<br />
assuming the circulation rate depends on the square of the nominal size.<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
75<br />
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© ISO 2004 – All rights reserved 75<br />
Licensee=Qatar Petroleum/5943408001
ISO 10432:2004(E)<br />
API Specification 14A / ISO 10432<br />
Table F.3 — SSCSV liquid flow rates (see B.15, B.16 and B.17)<br />
Nominal tubing or casing size<br />
Circulation rate<br />
m 3 /d (B/d)<br />
(± 10 %)<br />
mm (in) Class 1 and Class 2<br />
60,3 (2 3/8)<br />
73,0 (2 7/8)<br />
88,9 (3 1/2)<br />
101,6 (4)<br />
114,3 (4 1/2)<br />
127,0 (5)<br />
139,7 (5 1/2)<br />
165,1 (6 1/2)<br />
177,8 (7)<br />
79 (500)<br />
124 (780)<br />
178 (1 120)<br />
238 (1 500)<br />
305 (1 920)<br />
386 (2 430)<br />
477 (3 000)<br />
687 (4 320)<br />
935 (5 880)<br />
The manufacturer establishing sizes not covered by this specification may<br />
interpolate or extrapolate, assuming the circulation rate depends on the square of<br />
the nominal size.<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
76<br />
76 © ISO 2004 – All rights reserved<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
Licensee=Qatar Petroleum/5943408001
API Specification 14A / ISO 10432<br />
Annex G<br />
(informative)<br />
API Monogram<br />
G.0 Introduction<br />
The API Monogram Program allows an API Licensee to apply the API Monogram to products. Products<br />
stamped with the API Monogram provide observable evidence and a representation by the Licensee that,<br />
on the date indicated, they were produced in accordance with a verified quality management system and<br />
in accordance with an API product specification. The API Monogram Program delivers significant value<br />
to the international oil and gas industry by linking the verification of an organization's quality management<br />
system with the demonstrated ability to meet specific product specification requirements.<br />
When used in conjunction with the requirements of the API License Agreement, API Specification Q1,<br />
including Annex A, defines the requirements for those organizations who wish to voluntarily obtain an API<br />
License to provide API monogrammed products in accordance with an API product specification.<br />
API Monogram Program Licenses are issued only after an on-site audit has verified that the Licensee<br />
conforms to both the requirements described in API Specification Q1 in total, and the requirements of an<br />
API product specification.<br />
For information on becoming an API Monogram Licensee, please contact API, Quality Programs, 1220 L<br />
Street, N. W., Washington, DC 20005 or call 202-682-8000 or by email at quality@api.org.<br />
G.1 API Monogram Marking Requirements<br />
These marking requirements apply only to those API licensees wishing to mark their products with the<br />
API Monogram.<br />
There are no specific marking requirements for the API Monogram on API 14A SSSV equipment.<br />
Application of the API Monogram shall be per the manufacturers procedures as specified in API<br />
Specification Q1, which requires marking of the license number and date of original manufacture.<br />
G.2 Test Agency License Criteria<br />
G.2.1 The Test Agency performing validation testing must meet the requirements of Clause 6.5.3 and<br />
Annex A of this International Standard. In addition, for compliance with these API Monogram Program<br />
requirements, the Test Agency must be an Independent Third Party, and must be licensed by API in order<br />
to test SSSVs which are intended to be marked with the API Monogram.<br />
G.2.2 Laboratories desiring license under this Annex shall have a functional quality program in<br />
accordance with the ISO/IEC 17025 (formerly ISO/IEC Guide 25), “General Requirements for the<br />
Competence of Testing and Calibration Laboratories," and the requirements of API Spec Q1, except<br />
requirements related to product design, production, field nonconformance and nonconforming product<br />
release under concession. API shall maintain a list of licensed laboratories, which shall appear in the API<br />
Composite List of Manufacturers Licensed for use of the API Monogram. Laboratories desiring licensing<br />
under this Annex shall make application and pay fees as follows:<br />
Initial License Fee. The applicant will be assessed an initial license fee for the first Specification included<br />
in the application, and a separate fee for each additional Specification included in the application.<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
No reproduction or networking permitted without license from IHS<br />
77<br />
Licensee=Qatar Petroleum/5943408001<br />
Not for Resale, 06/08/2006 18:39:50 MDT
API Specification 14A / ISO 10432<br />
Annual License Fee. In addition to the initial license fee, laboratories will be assessed an annual renewal<br />
fee for each specification under which they are listed.<br />
G.2.3 The Laboratory shall submit a controlled copy of their Quality Manual to API. The manual will be<br />
reviewed by API Staff for conformance to the requirements of Section G.2.2 of this Annex and specific<br />
test methods identified in this or other API Specifications. Upon acceptance of the manual, API shall<br />
arrange an audit, as follows:<br />
Initial and Renewal Audits. First-time applicants and current licensed laboratories on every third year<br />
renewal of licensing shall be audited by qualified auditors. The parameters of these audits shall be the<br />
appropriate API Specifications and the laboratory’s API accepted quality manual. The audits will be<br />
performed to gather objective evidence for API’s use in verifying that the laboratory is in conformance<br />
with the provision of the Laboratory Quality Program as applicable to this API specification and the<br />
requirements of G.2.2 of this Annex. The laboratory will be invoiced for the cost of these audits.<br />
Periodic Audits. Existing laboratories will be periodically audited by an approved API auditor on a<br />
nondiscriminatory basis to determine whether or not they continue to qualify as a licensed laboratory. The<br />
frequency of the periodic audits will be at the discretion of the staff of the Institute. The costs of periodic<br />
audits will be paid by the Institute.<br />
G.2.4 Removal of Laboratory from Composite List shall occur due to the following:<br />
a. Failure to meet the requirements of the audit<br />
b. Failure to pay annual renewal fee<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
G.2.5 Reinstatement of License Rights<br />
Laboratories who have been suspended may request reinstatement at any time. If a request for<br />
reinstatement is made within sixty (60) days after suspension, and if the reason for suspension has been<br />
corrected, no new application is necessary. A re-audit of the laboratory’s facilities will be made by an<br />
approved Institute auditor prior to a decision to reinstate license rights. The laboratory will be invoiced for<br />
this re-audit regardless of the Institute’s decision on reinstatement. If the result of the re-audit indicates to<br />
the API staff that the laboratory is qualified, the Composite List will be updated.<br />
If request for reinstatement is made more than sixty (60) days after suspension, the license shall be<br />
cancelled, and the request shall be treated as a new application unless circumstances dictate and<br />
extension of this time period as agreed upon by the API staff.<br />
G.2.6 Appeals<br />
A licensed organization may appeal to API any decision to suspend or cancel the license. Appeals are<br />
subject to the appeals procedures of API and as detailed in the contract between API and the licensed<br />
organization.<br />
G.2.7 Any changes to a Licensed Laboratory’s Quality Assurance Manual must be accepted by API in<br />
writing prior to implementation.<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
No reproduction or networking permitted without license from IHS<br />
78<br />
Licensee=Qatar Petroleum/5943408001<br />
Not for Resale, 06/08/2006 18:39:50 MDT
API Specification 14A / ISO 10432<br />
ISO 10432:2004(E)<br />
Bibliography<br />
[1] ISO/IEC Guide 22:1996, General criteria for supplier's declaration of conformity<br />
[2] ISO/TS 29001:2003, Petroleum, petrochemical and natural gas industries — Sector-specific quality<br />
management systems — Requirements for product and service supply organizations<br />
[3] ISO 13679, Petroleum and natural gas industries — Procedures for testing casing and tubing<br />
connections<br />
[4] API Bull 5C3, Formulas and calculations for casing, tubing, drill pipe, and line pipe properties<br />
[5] API Bull 5C5, Recommended practice on procedures for testing casing and tubing connections<br />
[6] API RP 13B1, Standard procedure for field testing water-based drilling fluids<br />
[7] ASNT SNT-TC-1A, Personnel qualification and certification in nondestructive testing 7)<br />
[8] ASTM D638, Standard test method for tensile properties of plastics<br />
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
[9] ASTM D 1415, Standard Test Methods for Rubber Property — International Hardness<br />
[10] NACE MR0175/ISO 15156-1-2-3, Petroleum and natural gas industries — Materials for use in<br />
H 2 S-containing environments in oil and gas production 8)<br />
[11] SAE AS 568B, Aerospace size standard for O-rings<br />
[12] MIL STD 413, Visual inspection guide for elastomeric O-rings<br />
7) The American Society for Nondestructive Testing, 1711 Arlingate Lane, Columbus, OH 43228-0518, USA.<br />
8) NACE International, 1440 South Creek Drive, Houston, TX 77084-4906, USA.<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
79<br />
© ISO 2004 – All rights reserved 77<br />
Licensee=Qatar Petroleum/5943408001
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
No reproduction or networking permitted without license from IHS<br />
Licensee=Qatar Petroleum/5943408001<br />
Not for Resale, 06/08/2006 18:39:50 MDT
--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`---<br />
Additional copies are available through Global Engineering<br />
Documents at (800) 854-7179 or (303) 397-7956<br />
Information about API Publications, Programs and Services is<br />
available on the World Wide Web at http://www.api.org<br />
Product No: GX14A11<br />
Copyright American Petroleum Institute<br />
Provided by IHS under license with API<br />
No reproduction or networking permitted without license from IHS<br />
Licensee=Qatar Petroleum/5943408001<br />
Not for Resale, 06/08/2006 18:39:50 MDT
PART 3:<br />
• Form 175-454400<br />
Charlie Chong/ Fion Zhang
INSPECTION & TESTING REQUIREMENTS<br />
SAUDI ARAMCO FORM-175<br />
REVISION: 03/31/2013<br />
REPLACES: 06/15/2011<br />
CODE NUMBER:<br />
IR454400<br />
PAGE:<br />
1 of 2<br />
SCOPE: VALVE ASSEMBLY : <strong>Safety</strong> , <strong>Subsurface</strong>.<br />
TEST AND INSPECTION PER: API-14A, Purchase Order, and Specifications As Noted Below.<br />
0010<br />
(1) VISUAL INSPECTION WITNESSING BY INSPECTOR (Note 1)<br />
(2) CERTIFICATES / RECORDS TO BE CHECKED BY INSPECTOR<br />
(3) CERTIFICATES / DATA TO BE PROVIDED BY VENDOR / SUPPLIER / MANUFACTURER<br />
* * *<br />
Pre-Fabrication/Production Requirements Specification Details / Notes:<br />
0010 X Design Validation and Performance Data; Class of Service Per API 14A (Clause 5.1.2, 6.3.5, 6.5, and 7.9; Annex A, Annex<br />
B, Annex F)<br />
0020 X X Pre inspection Meeting Verify Company approval of Manufacturer Inspection and test<br />
Plan<br />
0030 X Written Material Specifications (Metals & Non-Metals) Per API 14A (Clause 6.3.4).<br />
0040 X Written Heat Treating Equipment Qualification Procedures Per API 14A (Clause 7.3)<br />
0050 X Written Coating and Overlay Procedures Per API 14A (Clause 7.5)<br />
0060 X Welding Procedure Specifications and Procedure Qualification<br />
Records<br />
Per ASME Section IX. Company approval required.<br />
0070 X Welders Qualification Records Per ASME Section IX.<br />
0080 X NDT Procedures Per API 14A (Clause 7.6.7). Company approval required;<br />
Verify valid approval of procedures<br />
0090 X Written Dimensional and Surface Inspection Procedures Per API 14A (Clause 7.6.1 - 7.6.4)<br />
0100 X Written Storage and Preparation for Transport Procedures Per API 14A (Clause 9). Company approval required.<br />
0110 X Raw Materials and Material Test Reports Per API 14A ( Clause 7.2-7.4 and 7.6.9); MTRs to be EN<br />
10204 Type 3.1<br />
0020<br />
* * *<br />
In process inspection & test requirement Specification Details / Notes:<br />
0010 X NDT Personnel qualification Per API 14A (Clause 7.6.8). Verify valid qualification of<br />
personnel<br />
0020 X X Nondestructive Testing: MT, PT, UT and RT Per API 14A (Clause 7.6.7).<br />
0030 X Heat Treatment Per API 671<br />
IR454400 Continued...
INSPECTION & TESTING REQUIREMENTS<br />
SAUDI ARAMCO FORM-175<br />
REVISION: 03/31/2013<br />
REPLACES: 06/15/2011<br />
CODE NUMBER:<br />
IR454400<br />
PAGE:<br />
2 of 2<br />
(1) VISUAL INSPECTION WITNESSING BY INSPECTOR (Note 1)<br />
(2) CERTIFICATES / RECORDS TO BE CHECKED BY INSPECTOR<br />
(3) CERTIFICATES / DATA TO BE PROVIDED BY VENDOR / SUPPLIER / MANUFACTURER<br />
0040 X Calibration of Measuring and Testing Equipment Per API 14A (Clause 7.6.6)<br />
0050 X Hardness Test Per ASTM A370 and NACE-MR-01-75 for pressure retaining<br />
components in sour service<br />
0060 X X Visual and Dimensional Inspection (all traceable components) Per API 14A (Clause 7.4 and 7.6.2-7.6.4) and P.O<br />
Specifications. All Traceable Components.<br />
0030<br />
* * *<br />
Final inspection & test requirements Specification Details / Notes:<br />
0010 X X Functional Test Per API 14A (Clause 6.7, 7.7, and Annex C); Per API 14A<br />
(Annex D), where specified in the purchase order.<br />
0020 X X Visual and Dimensional Inspection (assembly) Per API 14A (7.4 and Annex B.4) and P.O Specifications.<br />
0030 X Marking API 14A (Clause 7.8). Company purchase order and material<br />
number to be applied.<br />
0040 X X Documentation and Traceability Per API 14A (Clause 7.2-7.4, and 7.6.9; Annex F); MTRs to be<br />
EN 10204 Type 3.1.<br />
0040<br />
* * *<br />
Additional/Supplemental Requirements Specification Details / Notes:<br />
0010 X Thread Inspection and Seal Areas Per API 14A (Clause 7.6.5); For premium threads (i.e. non API<br />
5B threads) and for premium grades (i.e. non API).<br />
0020 X Thread Gauging of Thread End Per API 14A (Clause 7.6.5); Only for threads to API 5B.<br />
0030 X Supplied Documentation (Operating Manual) Per API 14A (Clause 7.9).<br />
0040 X Preparation for Shipment Per API 14A (Clause 9) and PO requirements.<br />
Notes:<br />
(1) May only be waived by the responsible Saudi Aramco, ASC, AOC Inspection Offices<br />
(2) See form SA175 - 000003 for instructions on using this form.<br />
(3) Drift shall be sized in accordance with API 14A Annex B.4; ID drift bars shall be non-metallic and at least 42" in length.<br />
(4) Exposed threaded connections shall have thread preservative applied and a closed end thread protector installed; external sealing elements<br />
shall be protected with materials that will prevent UV and impact damage.<br />
End of IR454400
Charlie Chong/ Fion Zhang
Charlie Chong/ Fion Fion Zhang Zhang