Knowing Subsurface Safety Valve- API14A

Knowing Subsurface Safety Valve 

Equipment 

to API14A & FORM-175 IR454400 

Reading for my Aramco inspection knowledge. 

Shanghai 7 

th June 2018 

Charlie Chong/ Fion Zhang

闭门练功 


Charlie Chong/ Fion Zhang 

Fion Zhang at Shanghai 

Damuqiao 大木桥路 

7 th June 2018


http://greekhouseoffonts.com/

The Magical Subsurface Safety Valve Reading 



Subsurface Safety Valve (SSSV) 

Down Hole Safety Valve (DHSV) 

SSSV 


Well Control 


https://www.youtube.com/embed/VW3yULTG9NY

Well Completion 


https://www.youtube.com/embed/iXdq65xzsus

PART: 

• Knowing Subsurface Safety Valves 

• API 14A 

• Form 175-454400 


Part 1: Knowing Subsurface Safety Valve (SSSV) 

A subsurface safety valve is essentially a shutdown valve installed at the 

upper wellbore for emergency shutdown to protect the production tubing and 

wellhead in case of overpressure. Purpose of a subsurface safety valve 

(SSSV) is to avoid the ultimate disaster which can result in release of 

reservoir fluids to the surroundings. This makes SSSV a very important 

component of a well completion. 

To protect the surface facilities in case of emergency, the wellbore is isolated 

from surface facilities using a subsurface safety valve (SSSV). Hence such a 

safety valve needs to be fail safe in order to isolate well bore in any kind of 

system failure or damage to surface production, control and safety facilities. 


http://www.enggcyclopedia.com/2012/02/subsurface-safety-valve-sssv/

Functioning of SSSV 

A subsurface safety valve is typically a uni-directional flapper valve, directed 

in such a way that the flappers open downwards when pressure is applied 

from an upward direction. The flapper can only open in the downward 

direction. So even if high pressure is applied by the well fluids from a 

downward direction, a safety valve can remain closed. This makes a 

subsurface safety valve fail-safe. To open the valve, hydraulic signal is sent 

from the surface well control panel. This hydraulic pressure is responsible for 

keeping the flappers of SSSV open and loss of hydraulic pressure result in 

closing of the valve. Thus wellbore can be isolated in case of system failure or 

damage to the surface facilities. 


Subsurface Safety 

Valve (SSSV) 


Subsurface safety valves provide 

the ultimate protection against 

uncontrolled flow from producing oil 

and gas wells in case of 

catastrophic damage to wellhead 

equipment. 

Their use offshore is legislated in 

many parts of the world to protect 

people and the environment. 

Safety valves have evolved from 

the relatively simple downhole 

devices of the 1940s to complex 

systems that are integral 

components in offshore well 

completions worldwide. 


https://www.slb.com/~/media/Files/resources/oilfield_review/ors02/win02/p52_64.pdf

Subsurface safety systems provide emergency, fail-safe closure to stop fluid 

flow from a wellbore if surface valves or the wellhead itself are damaged or 

inoperable. Safety valves are essential in offshore wells and in many land 

wells located in sensitive environments, or in wells that produce hazardous 

gases. They are installed to protect people, the environment, petroleum 

reserves and surface facilities. Successful installation, dependable operation 

and reliability of safety-valve systems are crucial to efficient and safe well 

performance. Perhaps the most regulated component of an oil or gas well, the 

safety-valve system must satisfy stringent technical, quality and operational 

requirements. Scrutiny of safety-valve design, manufacture and operation by 

regulatory bodies and operators requires valve manufacturers to apply a level 

of diligence and testing beyond that of related well-completion and flowcontrol 

equipment. This reflects the crucial role of safety valves. 



The winds and waves of Hurricane Lili impacted about 800 offshore facilities, 

including platforms and drilling rigs, as the Category 4 storm passed through 

the oil-producing region offshore Louisiana, USA, in September and October 

of 2002. Despite sustained winds of 145 miles/hr [233 km/hr], the US Minerals 

Management Service (MMS) reported that the storm caused no fatalities or 

injuries to offshore workers, no fires and no major pollution. Six platforms and 

four exploration rigs were damaged substantially by the storm. There were 

nine reported leaks of oil; only two exceeded one barrel. None of these spills 

was associated with the six severely damaged platforms. Prevention of 

accidents is an important aspect of the MMS safety strategy. The lack of 

significant news relating to spills during this storm is a testament to the 

success of established safety protocols. As part of the safety system, 

subsurface safety valves serve a relatively unglamorous but critical role. By 

working properly when other systems fail, these valves are a final defense 

against the disaster of uncontrolled flow from a well. 



Hurricane Lili 


In principle, a safety valve is a simple device. Most of the time it is open to 

allow flow of produced fluids, but in an emergency situation it automatically 

closes and stops that flow. To effect this task, sophisticated engineering 

designs and state-of-the-art materials have been developed. The valve’s 

closure mechanism must close and seal after months of sitting in the open 

position and years after its installation. 

Special procedures and technologies applied to reopening the valve after 

closure ensure its continued reliability. Wells are drilled and completed under 

diverse conditions, so before an appropriate subsurface safety valve is 

selected and installed, a thorough review of the reservoir, wellbore and 

environmental conditions must be conducted. 



This analysis should consider these 

factors throughout the predicted life of 

a completion, if not the life of a well. 

Oil and gas developments in 

deepwater and high-pressure, hightemperature 

(HPHT) reservoirs impose 

additional engineering challenges in 

the design and installation of safety 

valves. In such environments, where 

well intervention is both difficult and 

costly often exceeding several million 

dollars, excluding lost production the 

importance of reliable safety-valve 

operation is even greater. This article 

reviews the evolution, design and 

installation of subsurface safety valves 

through examples from operations in 

the North Sea and Gulf of Mexico. 



Disaster Drives Development 

The first safety device to control subsurface flow was used in US inland 

waters during the mid- 1940s. This Otis Engineering valve was dropped into 

the wellbore when a storm was imminent and acted as a check valve to shut 

off flow if the rate exceeded a predetermined value. A slickline unit had to be 

deployed to retrieve the valve. Those first valves were deployed only as 

needed, when a storm was expected. 

The use of subsurface safety valves was minimal until the state of Louisiana 

passed a law in 1949 requiring an automatic shutoff device below the 

wellhead in every producing well in its inland waters. Unfortunately, most 

disastrous situations occur unexpectedly. Surface facilities, including the 

surface safety systems, can be damaged by storms or vehicles impacting 

them. Boats dragging anchors or other devices can damage facilities on the 

bottoms of lakebeds or on the seafloor. Accidents have sometimes occurred 

when surface safety equipment is temporarily bypassed during logging and 

well intervention operations. 



The need for a new and more reliable type of subsurface safety valve was 

driven by accidents in Lake Maracaibo, Venezuela, in the mid-1950s. Tanker 

ships hitting platforms in the lake resulted in well blowouts. Producers wanted 

a valve that would protect the environment in case of severe damage to 

surface facilities, while maximizing production. The result was a surfacecontrolled 

valve that was normally closed—meaning the valve was closed 

unless an action kept it open. That action was fluid pressure transmitted to 

the valve through a hydraulic line from the surface. 

A 1969 blowout in a well in the Santa Barbara Channel off California, USA, 

led to 1974 regulations that required the use of subsurface safety systems on 

all offshore platforms and installations in US federal waters. These 

regulations relied on requirements and recommendations set forth by an 

American Petroleum Institute (API) task group comprising manufacturers and 

users of subsurface safety valves. The API has published key guidelines for 

many aspects of the design and completion of oil and gas wells. 



Lake Maracaibo 



1969 Blowout In A Well In The Santa Barbara Channel Off California 


The International Organization for Standardization (ISO) revised the work of 

the API task group to meet global needs. These ISO standards are widely 

applied for international offshore projects and also for many land-based 

developments. In the US, the MMS enforces the requirements of federal and 

state legislation. Similar government bodies, such as the Health and Safety 

Executive in the UK and the Norwegian Petroleum Directorate in Norway, 

perform this function in their respective countries. Standards and 

recommendations developed by various industry collaborations have led to 

higher safety awareness and a greater commitment to mitigate human and 

environmental risk. This is critically important as the industry moves to exploit 

petroleum reserves in operating conditions that are significantly more 

demanding and severe, and environmentally more sensitive than those 

confronted in 1974. The challenges of safe oil and gas production in 

deepwater and HPHT reservoirs elevate industry collaboration efforts from 

beneficial to essential. 



Safety-Valve Operations 

Modern safety valves are an integral part of systems that protect almost all 

offshore production installations and a growing number of land based facilities. 

These systems protect people and the environment, and limit unwanted 

movement of produced fluids to the surface. As insurance against disaster, 

they must lie essentially dormant for extended periods, but be operational 

when needed. Development of today’s sophisticated valves occurred in 

distinct steps. 



Early subsurface safety valves were actuated by a downhole change in 

production flow rate. A flow tube in such valves is equipped with a choke bean, 

which is a short, hard tube that restricts flow, creating a differential pressure 

between the top and bottom of the tube. Production fluid flowing through this 

choke creates a differential pressure across the bean—the pressure on the 

lower face of the choke bean is higher than the pressure on the upper face. 

When the force on the lower face exceeds the combination of pressure on 

the upper face and the force of the power spring holding the valve open, the 

flow tube moves up and allows the flapper to hinge into the flow stream and 

close against a seat, sealing off flow. The flow rate to close the valve can be 

set during manufacture by spring and spring-spacer selection and by 

adjusting the hole size through the bean. 



Typical subsurface-controlled safety valve. 

Early safety valves were relatively simple in 

operation and created a significant restriction to 

production. The force of the valve spring, FS, acts 

on the flow tube to keep the flapper valve in a 

normally open position. The pressure below the 

restriction is P1 and that above is P2. These 

pressures act on the exposed faces of the piston, 

creating a force F1 – F2 to close the valve. When 

fluid flows upward, the constriction creates a 

pressure differential that increases closure 

force. The spring force is preset for a specific 

flow rate, so when the flow rate reaches that 

critical rate, the piston moves up, releasing the 

flapper to close and shut off fluid flow. 



Typical subsurfacecontrolled 

safety valve. 

Early safety valves were 

relatively simple in operation 

and created a significant 

restriction to 

production. The force of the 

valve spring, FS, acts 

on the flow tube to keep the 

flapper valve in a normally 

open position. The pressure 

below the restriction is P1 and 

that above is P2. These 

pressures act on the exposed 

faces of the piston, creating a 

force F1 – F2 to close the 

valve. When fluid flows 

upward, the constriction 

creates a pressure differential 

that increases closure 

force. The spring force is 

preset for a specific flow rate, 

so when the flow rate reaches 

that critical rate, the piston 

moves up, releasing the 

flapper to close and shut off 

fluid flow. 


Safety valves that are actuated in this manner create a restriction in the 

wellbore that can limit production even when they are open. For many years 

after the introduction of safety valves in the 1940s, proration was in effect in 

the US market, so wells typically were produced at rates lower than their 

maximum deliverability. A hindrance to well-production efficiency caused by 

valve design and installation was not considered a serious issue at that time. 

These downhole-actuated or subsurface controlled safety valves have two 

major limitations. Since a significant variation in fluid flow or pressure is 

required to actuate them, these valves can be used only when normal 

production is restricted to a level that is less than the maximum capability of a 

well. This actuation level is adjusted and set before the safety valve is 

installed in the wellbore. Also, since a significant flow-rate change is required 

to actuate the shutoff, the valve will not operate in low-flow conditions in 

which fluid flow is less than the preset production level. 



A new type of valve became necessary when energy markets changed during 

the 1970s, and more production was demanded from wells. However, when 

well productivity is maximized, it may be difficult or impossible to have enough 

additional flow downhole to overcome the spring force and close a 

subsurface-controlled safety valve. Under such conditions, reliable operation 

of flow-velocity type subsurface-controlled equipment can no longer be 

assured. 

Controlling safety-valve operation from a surface control station and effecting 

reliable closure independent of well conditions were key objectives for design 

engineers. In the early 1960s, Camco, now a part of Schlumberger, 

introduced surface-controlled subsurface safety-valve (SCSSV) systems to 

meet these needs. Later design improvements led to an internal valve profile 

that creates minimal disruption to fluid flow within the production conduit 

while the valve is open. 



An SCSSV is operated remotely through a control line that hydraulically 

connects the safety valve, up and through the wellhead, to an emergency 

shutdown system with hydraulic-pressure supply. The design is fail-safe: 

through the control line, hydraulic pressure is applied to keep the valve open 

during production. If the hydraulic pressure is lost, as would occur in a 

catastrophic event, the safety valve closes automatically through the action of 

an internal power-spring system—a normally-closed fail-safe design. With an 

SCSSV, activation no longer depends on downhole flow conditions. External 

control also allows the valve to be tested when desired, an important 

improvement for a device that may be installed for years before its primary 

use is required. 



Surface-controlled subsurface safety valve 

(SCSSV). The more recent SCSSV design is a 

normally closed valve, with the spring force, FS, 

acting to push the piston upward and release the 

flapper to close the valve. Control pressure 

transmitted from surface through a hydrauliccontrol 

line acts against the spring to keep the 

flapper valve open during production. This 

concentricpiston design, which has been 

replaced in many modern valves by a rod-piston 

design, has a ring-shaped area between the 

piston and the valve body that the hydraulic 

pressure acts upon to generate the opening 

force FH. The small difference in the piston-wall 

cross sections between the upper (U) and lower 

(L) faces of the piston adds a small additional 

upward force, FL – FU. 




Surface-controlled subsurface safety valve (SCSSV). 



Closure systems 

Early safety-valve closure mechanisms typically had two main designs: 

• ball or 

• flapper-valve assembly. 

The ball-valve design is a sphere, the ball with a large hole through it. When 

this hole is aligned with the production tubing, flow is unimpeded. Rotating 

the ball 90˚ blocks flow. Ball valves are mechanically more complex to 

operate since linear movement of the control mechanism, often a piston, 

must be converted into rotational motion of the ball on the seal. The ballvalve 

mechanism also is sensitive to an increase in friction caused by debris 

or accumulations of scale or paraffin. 



The flapper-valve design, pioneered by Camco in the late 1950s, has become 

the most commonly used closure mechanism in the industry, including the 

challenging severe-service applications where reliability over the life of a well 

is required. A flapper acts like a door. A flow tube moves in one direction to 

push the flapper open and allow flow through the valve. Moving the flow tube 

back from the flapper allows a torsion spring to close the valve and block flow. 


https://production-technology.org/subsurface-safety-valve/

A flapper-valve mechanism is less susceptible to malfunction than a ballvalve 

assembly and offers several advantages during operation. Debris in the 

flow stream and solids buildup from scale or paraffin are less likely to prevent 

closure of a flapper valve than a ball valve. A ball valve can be damaged 

more easily by a dropped wireline tool or other equipment lost in the wellbore. 

Fluids can be pumped through flapper valves without damage to the flapper 

sealing surface. The primary function of a subsurface safety valve is to close 

and block flow when emergency conditions require halting well production. 

The API has set an acceptable leakage rate of 5 scf/min [0.14 m3/min] for 

newly manufactured subsurface safety valves. This is considered sufficient to 

contain the wellbore pressure. 



Schlumberger valves are tested to a more stringent standard than that 

required by the API specifications. A valve must close against 200 and 1200 

psi [1.4 and 8.3 MPa], and no more than one bubble of nitrogen can escape 

within 30 seconds at either test pressure differential. 



Key features of ball and 

flapper valves. A ball valve 

has a sphere with a hole 

through it, allowing flow 

through the valve when the 

hole is aligned with the tubing. 

Rotating the ball 90˚ places 

the solid part of the ball in the 

flow stream, stopping flow 

(top). The more common 

flapper valve works like a 

hinge with a spring. When the 

flow tube is down, the flapper 

is open, and when it is pulled 

up, the flapper closes 

(bottom). 


Typical safety-valve self-equalization mechanism. Manufactured from 

erosion-resistant materials, a self-equalization system is designed to operate 

on a fail-safe basis with minimal interruption to the overall integrity and 

operating reliability of the safety valve. 

Note: Self-equalizing mechanism: An integral equalizing mechanism 

eliminates the need to equalize differential pressure across the flapper. By 

venting shut-in pressure from below the safety valve to the tubing above the 

flapper, a valve can be equalized and can return the well to production 

quicker, safer, and more efficiently than when pumps and fluids must be used. 

Particularly effective is a through-the-flapper, metal-to-metal self-equalizing 

system that eliminates valve failure caused by erosion problems or buildup of 

fluid debris in the valve annulus. 


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 

https://www.youtube.com/embed/XByZEGbRgcM 


When the flapper is closed, as shown in the tool diagram and in the inset 

(left), the dart (red) rests in a seat and the flow tube (tan) is slightly above the 

flapper seal. A small increase in control pressure moves the flow tube down 

slightly and opens a flow path around the dart (middle). When the pressures 

above and below the flapper are equalized, the flow tube moves down to fully 

open the flapper valve, and the dart moves into another seat (right). 




SCSSV 


https://seabed.software.slb.com/production/WebHelp/production_model/domain_introduction/tubing_and_packers.htm



After actuation - After an 

incident that activates a safety 

valve, it may be necessary to 

pump weighted fluids downhole 

to control, or kill, the well. 

Safety valves are usually 

installed above most other 

downhole assemblies, so a 

method is needed to pass kill 

fluids through a closed safety 

valve. The increased pressure 

provided by pumping the wellcontrol 

fluids will open a flapper 

valve and allow fluids to pass 

easily through the safety-valve 

assembly. 



Once the kill-weight fluids are in place the flapper valve’s torsion spring will 

return it to the closed position. When it is time to put a well back on 

production, the safety valve must be reopened. Typically, the positive 

pressure from below holds the subsurface safety valve closed. In the earliest 

and simplest designs, tubing pressure was applied from surface to open the 

valve, but delivering the pressure required may be inconvenient or impractical 

due to availability of equipment or time and cost constraints. 



Flapper-type safety valves today include an actuation mechanism that opens 

the valve using a small pressure differential that does not damage the closure 

mechanism. Self-equalizing valves use the same actuation mechanism and 

also feature a mechanism to simplify equalizing pressure from above and 

below the closed flapper (previous page, right). When the self-equalizing 

valve is closed, there is a gap between the lower end of the flow tube and the 

flapper. A small increase in control-line pressure moves the flow tube down 

enough to unseat the equalizing dart, which opens a small flow path to the 

production tubing below the flapper. The pressure equalizes above and below 

the flapper, allowing the valve to open smoothly. The self-equalization 

mechanisms in ball valve designs require application of a high hydraulic 

pressure that may damage the more complex closure system inherent in 

these types of valves. 



Pressure Self-Equalizing Technology 

A subsurface safety valve will experience around one hundred slam 

processes during its lifetime. One of the fatal failure modes happening after 

such a closure of the flapper safety valve is its inability to open again. This 

failure occurs because of the extreme high pressure built up from the 

reservoir side, which can be much higher than the maximum hydraulic 

pressure supplied to open the flapper. One way to solve this problem is to drill 

open the dead flapper and superimpose a smaller valve to replace it. 

Although this remedy reduces the production rate of the well, it is still much 

better than killing the whole production string. Another way to solve this 

problem is by adding a pressure self-equalizing mechanism to the subsurface 

safety valve. The new design feature has been widely adopted by various 

industrial subsurface safety valve designers. Although detailed designs may 

vary from each other, the underlying ideas are quite similar. 


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 

sleeve tube will first push the poppet to the other side of the flapper. This will 

create a small channel for the flow to pass through the flapper, which helps to 

decrease the pressure differential. When the flapper is fully opened, the outer 

tube will push the plunger as well as the poppet back to its original position. 

However, every additional moving part will reduce the reliability of the 

subsurface safety valve. Possible fluid leakage and functional failure should 

be considered when including the pressure self-equalizing mechanism. In 

other words, a flapper design without pressure self-equalizing feature is more 

reliable than the one with such a feature. 


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 

mechanism or fluid path that bypasses the closure assembly presents a 

potential leak path that may contribute to safety-valve failure or malfunction. 

This potential is minimized as much as possible through rigorous designs and 

manufacturing methods that set high standards for accuracy, reliability and 

quality assurance. In certain applications, the functionality of an internal 

pressure-equalizing mechanism is an essential completion-design feature. It 

may not be possible to equalize pressure against a closed valve by pumping 

fluid into the wellbore at surface. For example, on isolated or remote wells, it 

may be difficult and expensive to pump fluid into a wellbore when needed; the 

equipment may not be readily available or may be expensive to transport to 

the location. For these wells, a selfequalizing valve may be used to minimize 

the pressure required at surface. Generally, the preferred option is to 

minimize use of self-equalizing systems during well design by selecting 

applications and operational procedures that do not require such valves. 



Halliburton Subsurface Safety Valve 


https://www.youtube.com/embed/EcdAa-lYGKw

Baker Hughes Subsurface Safety Valve 


https://www.youtube.com/embed/u-6q8uWInuQ

Conveyance systems - There are two typical methods for conveying and 

retrieving safety valves: tubing and slickline. The method chosen for a 

downhole application influences valve geometry and its effect on fluid flow 

from the wellbore. 

■ Tubing-conveyed, tubing-retrievable safety valves are designed to be an 

integral component of the production-tubing string and are installed during 

well completion with the tubular and other downhole equipment. For surface 

controlled valves, the hydraulic-control line to surface is attached directly to 

the safety valve and secured to the production-tubing string as it is run into 

the wellbore. The primary benefit of tubing-retrievable valves is that 

production is unhindered; the safety-valve internal diameter is essentially 

equivalent to that of the production tubing. The full-diameter bore also 

permits access to the lower wellbore with tools and instruments for flow 

control, well monitoring or service. 



Tubing-conveyed- Tubing-retrievable 

Surface Controlled Subsurface Safety Valves 


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 

the wellbore after the production-tubing string and surface wellhead 

equipment have been installed. It seats and locks into a special landing 

nipple that was placed in the production-tubing string at the desired setting 

depth, either as a component of the tubing string or as an integral element of 

the design of a tubing-conveyed safety valve. The landing nipple has a 

control line to surface to provide hydraulic pressure for operating the valve. In 

most cases, slickline- retrievable valves are easier and less expensive to 

remove from the wellbore or maintenance or inspection than tubingretrievable 

designs. 

Most tubing- retrievable valves are designed to use slickline-retrievable 

valves as a secondary system; if such a tubing retrievable valve malfunctions, 

the slickline retrievable valve can be installed until the next planned workover 

that requires tubing to be pulled. In a small percentage of completions, a 

slickline- conveyed valve system is used as the primary safety valve. 



A slickline- retrievable SCSSV must have a pressure connection with the 

hydraulic-control line from surface. The landing nipple has two polished 

areas on either side of hydraulic port. Sealing elements on the outside of the 

slickline retrievable valve mate with these polished bores in the nipple. Once 

a valve is locked in place, the seals contain the hydraulic pressure and 

separate it from wellbore fluids. 



Slick Line retrievable 

Surface Controlled Subsurface Safety Valves 


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 

slickline-retrievable system typically locks into a landing nipple in the 

completion string and seals on either side of the control-line port to isolate the 

control fluid from wellbore fluids (left). The tubing-retrievable system is an 

integral part of the completion string (right). The inside diameter of the valve 

is similar to the inside diameter of the production tubing. 







Slickline- Retrievable SCSSV 

https://www.youtube.com/embed/LmDJQW2OxyY 


Flapper Type SSV 

CTR's Tubing Retrievable Surface Controlled Sub Surface Safety Valve (TRSCSSSV) is piston 

rod activated flapper-type safety valve which is designed to shut in a well at a point below the 

surface. 


https://www.ctr.as/completion

Surface Controlled SSV- Flapper Type SSV 


https://www.ctr.as/completion

the 

Surface Controlled SSV- Flapper Type SSV 


Weatherford Slickline Retrievable SCSSV 


Material selection - In a wellbore environment, where fluids can be corrosive 

or erosive, and have the potential to precipitate scale and organic solids, it is 

difficult for any downhole equipment to maintain a high degree of readiness 

and reliability over an extended period of time. 

Flow-wetted parts, which are in contact with production fluids, must be 

designed to resist corrosion, erosion and the buildup of precipitates or solids. 

Flow-wetted surfaces of Schlumberger subsurface safety valves can be 

protected with a surface treatment of ScaleGard scale-deposition resistant 

coating. This is a Teflon- based product with an enhanced binder that is 

applied to surfaces by a spray and bake process. The 0.0013- to 0.002-mm 

(1.3μm-2.0μm ) (0.00005- to 0.00008-in.) thick coating does not interfere with 

the operation of completion- equipment assemblies with moving or 

reciprocating parts, and is slightly flexible. 



A ScaleGard treatment imparts the same excellent friction-reduction 

properties as Teflon material even under conditions of poor lubrication. Scale, 

which comprises various inorganic salts that precipitate from aqueous 

solution, resists adhering to parts with ScaleGard protection since Teflon 

surfaces resist wetting by both aqueous and organic solutions. ScaleGard 

coatings also have excellent chemical and heat resistance. Material selection, 

component design and the coating of flow-wetted parts contribute to the 

effectiveness and dependability of subsurface safety valves. 

The Camco* TRM-4 and -4H series tubing-retrievable, surface controlled, 

subsurface safety valves with ScaleGard protection . 


https://www.slb.com/~/media/Files/completions/product_sheets/safety_valves/trm_4_series_reduced.pdf

Valve-System Integrity 

In the past, safety-valve systems have malfunctioned because of failure or 

problems with components other than the SCSSV itself. For piston and 

flapper components in the device to operate properly, the control line, control 

fluid and surface control systems also must be designed, manufactured, 

installed and maintained properly. Small amounts of debris in the hydraulic 

control fluid have caused safety-valve systems to malfunction. The primary 

protection from this reliability hazard is to provide operating personnel with 

the facilities and training to apply high standards for operating and 

maintaining a subsurface safety system throughout its life. Additional 

protection comes from Schlumberger control-fluid filtering systems that can 

be installed in surface and downhole equipment to minimize this risk. Several 

deepwater safetyvalve designs now include this filtering system as an integral 

component to ensure operational integrity for the life of a well installation. 



The safety-valve control fluid must function properly throughout exposure to a 

wide range of temperatures and pressures. The fluid must maintain viscosity, 

lubricity and general conditions that ensure continuous satisfactory operation 

of a safety valve. The closing time for a safety valve—time elapsed between 

initiating action at the surface controls and valve closure—depends largely on 

• safety-valve design and 

• setting depth, and 

• viscosity of the control fluid. 

A control fluid must be matched to all anticipated operating conditions to 

ensure optimized performance of a safety valve. Historically, oil-base control 

fluids have been used. However, the control systems used for modern well 

systems often are designed to vent control pressure at the seafloor to reduce 

operating response time. Environmentally safe, water-base control fluids were 

developed for this function, and they typically maintain the high performance 

requirements of oil-base control fluids. Synthetic fluids are now available for 

situations in which the operating environment exceeds the chemical and 

temperature capabilities of water- or oil-base fluids. 


Functional Testing 

Safety valves typically undergo functional testing to API specifications at the 

time of manufacture; many local governmental bodies regulate and require 

such testing. Since operational sensitivities vary by type of valve, model and 

manufacturer, the specific operating manual must be consulted to establish 

operational procedures and constraints for a specific valve design. Advanced 

safety-valve systems should be engineered to handle a valve malfunction, so 

safe production can resume as quickly as possible. Many regulatory bodies 

prohibit production without a functional safety-valve system. The well should 

have contingency tools in place, with modes of operation prepared to resume 

or continue production safely until the next scheduled major intervention or 

workover. For example, as a contingency, some tubing-retrievable safety 

valve systems are designed to be locked open and have a slicklineretrievable 

safety-valve assembly inserted to use the same control system, 

as described above. Although the secondary valve assembly may restrict 

flow somewhat, production can be continued while preserving the necessary 

functionality for well safety. 



Heavy-wall Flow Couplings 

Turbulent flow can generate material loss from tubular walls above and below 

a restriction or profile change in production tubular, such as may occur with a 

safety valve. Heavy-wall flow couplings often are installed in the tubing 

above and below safety-valve assemblies to protect the string from damaging 

erosion at these points. Flow couplings are always recommended—in some 

cases required by regulation—with slickline- retrievable safety-valve 

assemblies, because of the greater restriction and increased turbulence 

created by the change in internal profile of the flow conduits. 



Bruce field, 

offshore Aberdeen, 

Scotland. On the right 

is a Bruce field 

wellbore design. The 

SCSSV is placed at 

the shallow depth of 

937 ft [286 m]. 

Chemical-injection 

mandrels are much 

lower in the well. 



Bruce field 


Bruce field 


Optimizing Flow Safely 

A systems approach frequently is used to select production tubulars and 

completion components for oil and gas wells. This ensures that the overall 

performance of the assembled completion string is compatible with reservoir 

deliverability and that the conduit between the reservoir and surface facilities 

is efficient. Completions are designed to minimize the effects of corrosion and 

erosion to be expected from produced fluids and solids. Production conditions 

can change or may exceed expected performance such that it may be 

possible to produce a well at rates higher than anticipated. Production 

engineers then have two options if they wish to use the existing completion: 

constrain production according to the limitations of the original completion 

design; or investigate how production levels can be increased while 

maintaining an acceptable safety factor within the limits of installed equipment. 


BP adopted the latter approach for gas wells in the Bruce field, located in the 

northern North Sea (previous page). Development began in 1992, with first oil 

and gas produced in 1993. A study to assess the impact of production 

changes on safety-valve operation focused on subsea wells completed in the 

late 1990s with 51⁄2-in. tubing and Camco TRM-4PE tubing-retrievable safety 

valves. This valve design incorporates non elastomeric dynamic seals—made 

of a spring-energized filled Teflon material—and a self-equalizing system 

(right). Well testing and early production data supported a rock-mechanics 

finding that the Bruce reservoir formation was competent and had minimal 

potential for sand production. Recently revised operating guidelines adopted 

by BP at Bruce field had identified 230 ft/sec [70 m/s] as the maximum fluid 

velocity for nominal solids-free gas production (sand production

TRM-4PE safety-valve 

assembly used in the Bruce 

field. The tubing retrievable 

TRM series has a compact 

and simple design suitable for 

a wide range of completion 

types. The number of seals 

and connections incorporated 

within the valve assembly is 

minimized to reduce the risk 

of leakage. 


Gas Slam Testing 

BP estimated that the additional production allowed by increasing the fluidvelocity 

limit from 110 to 230 ft/sec on the Bruce field wells would be 15 to 20 

MMscf/D [425,000 to 566,000 m3/d] for each well. Recompletion or workover 

to allow this increase in production was not considered feasible, so the limits 

on SCSSV performance and capability were re-evaluated. Operational testing 

of subsurface safety valves under flowing conditions, known as gas slam 

testing, is routinely performed as part of the product design-validation process, 

using API and ISO specifications. These standard tests are performed at 

relatively low flow rates—tens of feet per second. 


For higher gas flow-rate conditions, specialized equipment is required to slam 

test valves and monitor valve performance. The previous Schlumberger flowrate 

restriction of 110 ft/sec for operation of the TRM-4PE-series safety valve 

was set using these conventional design tests. Additional safety-valve slam 

tests were performed at the BG Technology Limited test facility at Bishop 

Auckland in the UK, one of only three facilities worldwide capable of 

performing such gas-slam tests under conditions that are as close as possible 

to Bruce field conditions. The primary objective of these tests was to 

determine if the TRM-4PE-series safety valves could be safely and reliably 

used at producing conditions of 230 ft/sec. 

Part of this process established the maximum gas-flow velocity against which 

the safety valve will slam closed multiple times while maintaining reliable 

operation and sealing to an acceptable leak rate—the specified API 

allowable leak rate of 5 scf/min. Reliable operation is determined by 

measuring repeatable and consistent valve hydraulic operating pressures. 

The gas-slam-testing procedure and associated instrumentation were 

designed to monitor performance of key safety-valve components including 

the flapper and seat mechanism, hydraulic system and equalizing valveactivation 

mechanism. 


Valve closure was tested at a series of mass flow rates with visual inspection 

of critical components after each test series. Initial tests at 110 ft/sec were 

first conducted to establish a baseline for the operating performance of the 

valve hydraulic system and closure mechanism. Staged increases in mass 

flow rate were applied (below). Precise measurements of leakage were made 

upon initial closure and again following five open and close cycles. The goal 

was to successfully test the safety valve at 230 ft/sec. This was achieved, and 

additional, more aggressive flow rates were applied to establish the limit of 

the current valve design. Tests of 400 ft/sec [122 m/s] were successfully 

applied to effect closure, although the rate of 350 ft/sec [107 m/s] was 

deemed to be the reliable limit of operation for the standard valve 

components in use. 


Gas Slam Testing 

* The specified API allowable leak rate is 5 scf/min [0.14 m 3 /min] 


As a result of testing performed on the safety valve and the engineering 

study conducted on the completion system, the production- rate limit for the 

applicable Bruce field wells was increased from 110 to 230 ft/sec. This 

increase was made with the knowledge that equipment performance was 

assured and that any questions relating to the safety or security of the well 

had been successfully resolved. After 12 months, the incremental rate benefit 

from each of the rate-constrained wells in the Bruce field was 9 MMscf/D 

[255,000 m3/d] and 400 B/D [63.6 m3/d]. In addition, the test results imply 

rate increases may be considered for additional completions with similar 

SCSSV installations. 


Valve-System Considerations 

Since the 1980s, several oil and gas companies have collaborated on a major 

study of SCSSV reliability, including data from valve manufacturers and 

operating companies with offshore interests in Brazil, Denmark, The 

Netherlands, Norway and the UK. The study, originally undertaken by the 

Foundation for Scientific and Industrial Research at the Norwegian Institute of 

Technology (SINTEF) and currently managed by Wellmaster, remains the 

largest yet undertaken into subsurface safety-valve operational experience. 

Conclusions of the SINTEF report from 1989 have influenced safety-valve 

development in the years since. These conclusions include the following 

findings: 

• Tubing-retrievable safety valves are more reliable than slicklineretrievable 

valves. 

• Flapper valves are more reliable than ball valves. 

• Non-equalizing valves are more reliable than self-equalizing valves. 

• The need for routine functional testing to identify problems should be 

balanced against the risk of imposing conditions or damage during testing 

that affect the operation or reliability of safety valves. 


SINTEF 

Visit of the Vresova IGCC power plant with representatives of Czech Technical University, SINTEF Energy Research and the 

Norwegian Research Council (Photo: SINTEF Energy) 


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 

quality assurance in materials and construction continue to improve the 

reliability of safety-valve systems while meeting the stringent gas-slam testing 

requirements and need for large dimensions for flow of modern highproduction 

well designs. 

The SINTEF and Wellmaster studies show that mean time to failure MTTF of 

tubing-retrievable flapper valves improved from 14 years in 1983 to more than 

36 years in a 1999 study. 


Technical and economic influences drive the development of technology in 

different ways. Current subsurface safety-valve application categories can be 

segmented broadly as: 

• conventional, 

• HPHT and 

• deepwater. 

Conventional safety-valve systems are installed in predictable or known 

wellbore conditions and require little or no specialist engineering or materials. 

Operators anticipate such wells will have some form of economically viable 

well intervention during their life, which typically is less than that of advanced 

wells for which intervention is not planned or feasible. The key driver in 

selecting components in a conventional installation is reliability at an 

economic price. Completion designs for HPHT and deepwater environments 

have a higher standard of reliability, with an emphasis on safe and efficient 

operation that optimizes production from the reservoir through the entire life 

of a well. These more extreme applications require proven design concepts 

that minimize the number of seals and connections to reduce potential leak 

paths, and use materials that will be unaffected by the anticipated 

environment and applied loads throughout the life of a valve. 


These more extreme applications require: 

• proven design concepts that 

• minimize the number of seals and connections to reduce potential leak 

paths, and 

• use materials that will be unaffected by the anticipated environment and 

applied loads throughout the life of a valve. 


Interventions are becoming more costly, even when they are planned in 

advance. Well-completion components must last over increasingly extended 

periods. The costs, complexity and hazards caused by initiation of workover 

operations or slickline interventions may be prohibitive on subsea wells. The 

engineering and quality assurance activities for such demanding and 

interdependent design conditions typically require solutions to be developed 

on a case-by-case or project basis. Engineers and designers of downhole 

equipment are under constant pressure to make the most of available 

wellbore geometry without sacrificing reliability or system value. Casing size 

is largely determined by drilling conditions, so engineers who design 

completion equipment, including safety valves, must provide the desired 

functionality without sacrificing available flow area in the production conduit. 

High-strength materials allow reduction in the wall thickness of components, 

although compatibility with any potentially corrosive fluids in a wellbore also 

must be examined. 


Similarly, designing valves for HPHT installations requires a more rugged 

construction for load- or pressure-bearing components. Advanced material 

selection and component design are the key tools in resolving this problem. 

The innovative curved flapper closure system is one example of how creative 

design engineers have managed to increase the safety-valve internal 

diameter without increasing the external dimensions of a valve assembly 

(below). Safety valves with curved flappers match the internal and outside 

diameters of smaller casing sizes better than previously thought possible. 


Safety-valve curved flapper. The 

curved flapper design allows a 

larger inside diameter for the 

production conduit. The wings of 

the flapper are profiled to fit within 

a smaller radius than would be 

possible with a conventional flatflapper 

design. This can offer 

important advantages when 

wellbore or safety-valve geometry 

is critical. 


Setting Valves at Great Depth 

The depth for placing an SCSSV is limited by the hydraulic working area 

required to effect closure of the valve. Today, essentially all subsurface safety 

valves are normally closed valves, requiring a positive force to keep them 

open. 

That force is supplied by pressure in the hydraulic-control line to surface, but 

the constant force that is applied is the hydrostatic pressure of the fluid in the 

hydraulic line. In the event of control-line leakage, the control pressure could 

increase if a denser fluid from the tubing annulus leaks into the control line. 

To ensure fail-safe operation, the closing pressure of a safety- valve spring 

mechanism must exceed the pressure potentially applied in either of these 

cases. 


Camco introduced a rod-piston actuation system in 1978 that has been 

adopted by the industry for both tubing- and wireline- retrievable valves . 

The hydraulic area is restricted to the cross- sectional area of a small rod 

piston that operates the flow tube. In addition to dramatically decreasing the 

effect of control-fluid hydrostatic pressure, the seal diameters are smaller, so 

less force is needed to overcome seal friction. Setting depths in excess of 

2000 ft [609 m] true vertical depth (TVD) are possible with a rod-piston valve. 

With even smaller rod-piston designs, deep- set valves can be rated to work 

at 8000 ft [2438 m] TVD. Several mechanisms have been used to overcome 

this depth restriction, including balance lines and gas-spring systems. 


Rod-piston 

SCSSV. In this 

valve design, 

the hydrauliccontrol 

pressure, FH, 

acts on a rod 

piston, 

replacing the 

larger, ringshaped 

hydraulic area 

of a concentricpiston 

valve 

design. This 

much smaller 

cross-sectional 

area allows 

smaller springs, 

which is 

significant for 

valves placed 

at great depth. 


Greater depth can also be achieved by using a gas spring—a nitrogencharged 

chamber—as a balancing force that acts in conjunction with the 

valve power spring. This charge is preset to reflect the worst-case hydrostatic 

pressure in the hydraulic-control line at the valve’s installed depth, thus 

following valve-setting depths greater than 12,000 ft [3658 m] TVD. Recently, 

three TRCDH safety valves were placed at depths ranging from 10,047 to 

10,060 ft [3062 to 3066 m] in the Gulf of Mexico, setting an industry record. 


Higher well pressures and temperatures also required changes in SCSSV 

seal design. Elastomeric sealing materials are susceptible to degradation at 

high temperature and in hostile chemical environments. Over time, the 

reliability and efficiency of a safety valve using elastomeric sealing may 

deteriorate. Camco developed the first safety valve that replaces elastomeric 

seals with metal-to-metal sealing systems. In recent years, this technology 

has been coupled with metal spring-energized filled Teflon sealing systems to 

meet the ever-increasing severity of safety-valve applications. Exploiting 

reservoirs in deep water depends on solving technical challenges that only a 

few years ago were thought to be insurmountable. Kerr-McGee Oil & Gas 

Corp. focuses on developing high-potential core-production areas, such as 

the frontier deepwater environment, with a rigorous approach to cost, quality 

and technology. Their expertise and rapid response to opportunities and 

challenges allow Kerr-McGee to complete developments and achieve early 

production within aggressive time frames. The Nansen and Boomvang 

developments that came on stream in the first half of 2002 benefited from this 

approach (above). 


Located in the Gulf of Mexico about 135 miles [217 km] south of Galveston, 

Texas, USA, the Nansen field lies in 3678 ft [1121 m] of water The field is 

developed with a combination of subsea, wet-tree wells and dry-tree wells on 

the platform (for more on wet and dry trees, see “High Expectations from 

Deepwater Wells,” page 36). At this water depth, a deep-set safetyalve 

system with a nitrogen-charged spring is required. With this system, the 

safety valve also can be positioned below the critical area in a wellbore where 

formation of scale, paraffin or similar wellbore deposits could impact the 

operation or reliability of the valve-closure mechanism. The neighboring 

Boomvang field was developed in parallel using similar technologies. Kerr- 

McGee had a long, successful history using Camco subsurface safety valves, 

including the tubing-retrievable TRC-DH series deep-set safety valve, and 

experience working with Schlumberger on previous projects. The company 

involved Schlumberger engineers in well planning and completion design for 

the Nansen project. The TRC-DH safety valve was used for both subsea and 

platform wells on the Nansen development. 


Nansen field, Gulf of Mexico. The Nansen facilities were constructed with a 

truss spar, shown in the photograph. 


Nansen field 


TRC-DH safety-valve 

assembly used in the 

Nansen field. Dual 

operating pistons 

allow operational 

redundancy. A gasspring 

mechanism is 

designed to balance 

the weight of the 

control-line fluid and 

allows use of low 

control pressure at 

surface. This valve is 

designed for deep-set 

and high-pressure 

applications. The flow 

tube rests on the 

nose seal when the 

flapper is open. This 

spring-loaded Teflon 

ring prevents debris 

and solids from 

accumulating in the 

flapper and seat 

areas. 


Close cooperation between Kerr-McGee and Schlumberger engineers helped 

resolve challenges efficiently without impacting the critical timeline. For 

example, long lead times often are required for material sourcing in ambitious 

projects, so requirements for special materials or unusual equipment 

specifications were identified early. This included obtaining material for 

manufacturing valve components, because the relatively large diameter of 

safety-valve components requires material in sizes that are not always 

commonly available. Kerr-McGee engineers demanded redundant features 

and safe operating characteristics. The TRC-DH safety-valve series was 

specifically developed for this type of deepwater application. The valve design 

incorporates a dual-piston operated control system that provides complete 

operating redundancy. The gas-spring system provides substantially lower 

control-line pressures at greater setting depths compared with conventional 

valve systems. The surface controlline pressure for gas-spring valves in the 

Nansen installation is less than 5000 psi [34.5 MPa] at surface, compared 

with 10,000 psi [68.9 MPa] that would be required for conventional valve 

operating systems. 


Nansen field wellbore diagram. The 

chemical injection mandrels are placed 

above the SCSSV in the Nansen field. 


Using this valve series contributes significantly to reliability of the control and 

operating system and reduces hazards associated with extreme-pressure 

hydraulic systems. Kerr-McGee selected 31⁄2-in. TRC-DH-10-F tubingretrievable 

safety valves for all three of the subsea wells tied to the Nansen 

development (above). The nine dry-tree wells used eight 31⁄2-in. valves and 

one 41⁄2-in. valve. Three 41⁄2-in. valves of the same specification were 

selected for critical subsea completions in the neighboring Boomvang 

development. The compact design of the TRC-DH safety valves provides 

the principal dimensions of 5.750-in. outside diameter (OD) and 2.750-in. 

inside diameter (ID) for the 31⁄2-in. valves, and 7.437-in. OD with 3.688-in. ID 

for the 41⁄2-in. valves. Most of the components for this safety valve series are 

machined from 13 chrome high strength stainless steel, resulting in a 

working pressure of 10,000 psi for both valve sizes. The valve design 

incorporates a nose-seal system on the flow tube. This is a spring-loaded 

Teflon ring that the bottom of the flow tube rests on when open, thereby 

preventing debris and solids from accumulating in the flapper and seat. 


Work on these subsea wells requires a deepwater drilling rig for well access, 

costly and production- delaying process that reinforces the need for reliability 

in safety-valve operation. The dual operating systems incorporated in each 

valve are independent and fully redundant control systems. This significantly 

reduces the risk of having to perform a well intervention or workover operation 

should there be a hydraulic-control system problem within the downhole 

safety-valve system. A project-management approach to the selection, 

manufacture and installation of the safety valve and associated system 

components during this multi-well project allowed lessons learned to be 

quickly incorporated into the design process for subsequent installations. 

For example, during the Nansen project, minor changes in material 

specification, product design and installation procedures were implemented 

as early experience highlighted opportunities for improvement. Engineering 

design changes and amended procedures improved the control-line clamping 

system, which simplified safety-valve installation. This level of integration 

gives both suppliers and manufacturers a shared responsibility for safety and 

environmental issues that are key success indicators for projects such as the 

Nansen development. 


To date, Kerr-McGee and Schlumberger have installed 10 safety valves, all of 

which are operating as designed and without failure. The successes and 

lessons learned at Nansen and Boomvang fields—including metallurgy, 

manufacture, design, operations and personnel aspects for safety-valve 

systems—will be carried forward to other deepwater developments in the 

Gulf of Mexico. 

Future Challenges 

The trend toward more complex reservoir development continues to present 

challenges for designers of safety-valve systems. Petroleum reserves today 

are exploited from deeper water and in harsher producing and operating 

conditions than ever before. In these more hostile conditions, material 

selection is critical for increasing equipment resistance to corrosion and 

material degradation over extended production periods. An essentially 

unlimited setting depth could be achieved by developing subsurface safety 

valves that incorporate solenoids to activate the valve. This would alleviate 

the problem of pressure contributions from the weight of fluid in the control 

line or leaks in that line. 


The need for compact equipment and close engineering tolerances also 

presents design and engineering challenges for valves placed in extreme 

environments. 

Advanced coating materials and application techniques, such as the 

ScaleGard coating, have been developed to enhance resistance to surface 

deposits on flow wetted and selected valve components. Recent 

improvements in chemical-injection technology allow use of ScaleGard 

coating within the safety valve to prevent accumulations of production borne 

contaminants and help to ensure safety valve system reliability. Larger 

safety-valve sizes will soon be needed. In some areas, for example Norway, 

plans for mono-bore completions with large-diameter production tubulars 

highlight the need for 9 5⁄8-in. safety-valve systems. The forces resulting 

from pressure acting on such large component areas are far beyond those of 

conventionally sized equipment and present significant additional challenges 

to design engineers. 


The success and reliability of features developed in the past are key to the 

development of innovative safety valves for the future. Use of electronic 

control equipment in advanced completion systems is increasing (see 

“Advances in Well and Reservoir Surveillance,” page 14.) This technology 

has proven its reliability and functionality, providing real-time indications of 

production behavior. State-of-the-art equipment now delivers these real-time 

advantages to downhole safety systems in situations that, above all others, 

require rapid response. This critical component of a safety system requires 

focus and expertise to continue development and ensure safety and efficient 

operation throughout a well’s life. —MA/BA/GMG 



https://www.weatherford.com/en/documents/brochure/products-and-services/drilling/metalskin%C2%AE-monobore-open-hole-liner-system/

PART 2: 

• API 14A 


--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

Specification for Subsurface Safety 

Valve Equipment 

ANSI/API SPECIFICATION 14A 

ELEVENTH EDITION, OCTOBER 2005 

EFFECTIVE DATE: MAY 1, 2006 

ISO 10432: 2004, (Identical) Petroleum and natural 

gas industries—Downhole equipment—Subsurface 

safety valve equipment 

Copyright American Petroleum Institute 

Provided by IHS under license with API 

No reproduction or networking permitted without license from IHS 

Licensee=Qatar Petroleum/5943408001 

Not for Resale, 06/08/2006 18:39:50 MDT

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Special Notes 

API publications necessarily address problems of a general nature. With respect to particular 

circumstances, local, state, and federal laws and regulations should be reviewed. 

Neither API nor any of API’s employees, subcontractors, consultants, committees, or other assignees 

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API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to 

assure the accuracy and reliability of the data contained in them; however, the Institute makes no 

representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims 

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API publications are published to facilitate the broad availability of proven, sound engineering and 

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Any manufacturer marking equipment or materials in conformance with the marking requirements of an 

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does not represent, warrant, or guarantee that such products do in fact conform to the applicable API 

standard. 

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These materials are subject to copyright claims of ISO, ANSI and API. 

All rights reserved. No part of this work may be reproduced, stored in a retrieval system, or 

transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without 

prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L 

Street, N.W., Washington, D.C. 20005. 

Copyright © 2005 American Petroleum Institute 






API Foreword 

This standard shall become effective on the date printed on the cover but may be used voluntarily from 

the date of distribution. 

This American National Standard is under the jurisdiction of the API SC6 - Subcommittee on Valves & 

Wellhead Equipment. This standard is considered identical to the English version of ISO 10432:2004. 

ISO 10432 was prepared by Technical Committee ISO/TC 67, Materials, equipment and offshore 

structures for petroleum, petrochemical and natural gas industries, SC 4, Drilling and production 

equipment which was based on the prior API Specification 14A, Ninth Edition. 

The following editorial corrections were incorporated: 

• 7.3.1.c.1 Reference should be to Section 4. 

• 7.7.4 Replace “…specifies if the optional…” with 

“…specifies, the optional…” 

• Informative Annex G “API Monogram” was added. 

Standards referenced herein may be replaced by other international or national standards that can be 

shown to meet or exceed the requirements of the referenced standard. Manufacturers electing to use 

another standard in lieu of a referenced standard are responsible for documenting equivalency. 

Nothing contained in any API publication is to be construed as granting any right, by implication or 

otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters 

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liability for infringement of letters patent. 

This document was produced under API standardization procedures that ensure appropriate notification 

and participation in the developmental process and is designated as an API standard. Questions 

concerning the interpretation of the content of this publication or comments and questions concerning the 

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Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A 

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Suggested revisions are invited and should be submitted to the Standards and Publications Department, 

API, 1220 L Street, NW, Washington, DC 20005, standards@api.org. 

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API Specification 14A / ISO 10432 

Contents 

API Foreword .......................................................................................................................................................... ii 

Foreword ................................................................................................................................................................ iv 

Introduction ............................................................................................................................................................. v 

1 Scope .......................................................................................................................................................... 1 

2 Normative references ................................................................................................................................ 1 

3 Terms and definitions ............................................................................................................................... 3 

4 Abbreviated terms ..................................................................................................................................... 7 

5 Functional specification ........................................................................................................................... 8 

5.1 General ....................................................................................................................................................... 8 

5.2 SSSV functional characteristics .............................................................................................................. 8 

5.3 Well parameters ......................................................................................................................................... 9 

5.4 Operational parameters ............................................................................................................................ 9 

5.5 Environmental compatibility .................................................................................................................. 10 

5.6 Compatibility with related well equipment ............................................................................................ 10 

6 Technical specification ........................................................................................................................... 10 

6.1 Technical requirements .......................................................................................................................... 10 

6.2 Technical characteristics of SSSV ........................................................................................................ 10 

6.3 Design criteria .......................................................................................................................................... 11 

6.4 Design verification .................................................................................................................................. 14 

6.5 Design validation ..................................................................................................................................... 14 

6.6 Design changes ....................................................................................................................................... 15 

6.7 Functional test ......................................................................................................................................... 15 

7 Supplier/manufacturer requirements .................................................................................................... 16 

7.1 General ..................................................................................................................................................... 16 

7.2 Raw material ............................................................................................................................................. 16 

7.3 Heat-treating-equipment qualification ................................................................................................... 17 

7.4 Traceability ............................................................................................................................................... 17 

7.5 Components undergoing special processes ........................................................................................ 18 

7.6 Quality control ......................................................................................................................................... 18 

7.7 SSSV functional testing .......................................................................................................................... 23 

7.8 Product identification .............................................................................................................................. 23 

7.9 Documentation and data control ........................................................................................................... 24 

7.10 Failure reporting and analysis ............................................................................................................... 26 

8 Repair/redress .......................................................................................................................................... 26 

8.1 Repair ........................................................................................................................................................ 26 

8.2 Redress ..................................................................................................................................................... 26 

9 Storage and preparation for transport .................................................................................................. 26 

Annex A (normative) Test agency requirements ................................................................................................ 27 

Annex B (normative) Validation testing requirements ....................................................................................... 30 

Annex C (normative) Functional testing requirements ...................................................................................... 40 

Annex D (informative) Optional requirement for closure mechanism minimal leakage ................................. 46 

Annex E (informative) Operating envelope ......................................................................................................... 47 

Annex F (normative) Data requirements, figures/schematics, and tables ....................................................... 49 

Annex G (informative) API Monogram ...................................................................................................................77 

Bibliography .......................................................................................................................................................... 79 

Page 

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iii 



ISO 10432:2004(E) 


Foreword 

ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies 

(ISO member bodies). The work of preparing International Standards is normally carried out through ISO 

technical committees. Each member body interested in a subject for which a technical committee has been 

established has the right to be represented on that committee. International organizations, governmental and 

non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the 

International Electrotechnical Commission (IEC) on all matters of electrotechnical standardization. 

International Standards are drafted in accordance with the rules given in the ISO/IEC Directives, Part 2. 

The main task of technical committees is to prepare International Standards. Draft International Standards 

adopted by the technical committees are circulated to the member bodies for voting. Publication as an 

International Standard requires approval by at least 75 % of the member bodies casting a vote. 

Attention is drawn to the possibility that some of the elements of this document may be the subject of patent 

rights. ISO shall not be held responsible for identifying any or all such patent rights. 

ISO 10432 was prepared by Technical Committee ISO/TC 67, Materials, equipment and offshore structures 

for petroleum, petrochemical and natural gas industries, Subcommittee SC 4, Drilling and production 

equipment. 

This third edition cancels and replaces the second edition (ISO 10432:1999), which has been technically 

revised. 

iv 



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iv 


© ISO 2004 – All rights reserved


ISO 10432:2004(E) 

Introduction 

This International Standard has been developed by users/purchasers and suppliers/manufacturers of 

subsurface safety valves intended for use in the petroleum and natural gas industry worldwide. This 

International Standard is intended to give requirements and information to both parties in the selection, 

manufacture, testing and use of subsurface safety valves. Furthermore, this International Standard addresses 

the minimum requirements with which the supplier/manufacturer is to comply so as to claim conformity with 

this International Standard. 

Users of this International Standard should be aware that requirements above those outlined in this 

International Standard may be needed for individual applications. This International Standard is not intended 

to inhibit a supplier/manufacturer from offering, or the user/purchaser from accepting, alternative equipment or 

engineering solutions. This may be particularly applicable where there is innovative or developing technology. 

Where an alternative is offered, the supplier/manufacturer should identify any variations from this International 

Standard and provide details. 

The requirements for lock mandrels and landing nipples previously contained in this International Standard are 

now included in ISO 16070. 

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v 

© ISO 2004 – All rights reserved v 

Licensee=Qatar Petroleum/5943408001

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INTERNATIONAL STANDARD API Specification 14A / ISO 10432 

ISO 10432:2004(E) 

Petroleum and natural gas industries — Downhole 

equipment — Subsurface safety valve equipment 

1 Scope 

This International Standard provides the minimum acceptable requirements for subsurface safety valves 

(SSSVs). It covers subsurface safety valves including all components that establish tolerances and/or 

clearances which may affect performance or interchangeability of the SSSVs. It includes repair operations and 

the interface connections to the flow control or other equipment, but does not cover the connections to the well 

conduit. 

NOTE Limits: The subsurface safety valve is an emergency safety device, and is not intended or designed for 

operational activities, such as production/injection reduction, production stop, or as a backflow valve. 

Redress activities are beyond the scope of this International Standard, see Clause 8. 



2 Normative references 

The following referenced documents are indispensable for the application of this document. For dated 

references, only the edition cited applies. For undated references, the latest edition of the referenced 

document (including any amendments) applies. 

ISO 48, Rubber, vulcanized or thermoplastic — Determination of hardness (hardness between 10 IRHD and 

100 IRHD) 

ISO 527-1, Plastics — Determination of tensile properties — Part 1: General principles 

ISO 2859-1, Sampling procedures for inspection by attributes — Part 1: Sampling schemes indexed by 

acceptance quality limit (AQL) for lot-by-lot inspection 

ISO 3601-1, Fluid power systems — O-rings — Part 1: Inside diameters, cross-sections, tolerances and size 

identification code 

ISO 3601-3, Fluid systems — Sealing devices — O-rings — Part 3: Quality acceptance criteria 

ISO 6506-1, Metallic materials — Brinell hardness test — Part 1: Test method 

ISO 6507-1, Metallic materials — Vickers hardness test — Part 1: Test method 

ISO 6508-1, Metallic materials — Rockwell hardness test — Part 1: Test method (scales A, B, C, D, E, F, G, H, 

K, N, T) 

ISO 6892, Metallic materials — Tensile testing at ambient temperature 

ISO 9000:2000, Quality management systems — Fundamentals and vocabulary 

ISO 9712, Non-destructive testing — Qualification and certification of personnel 

ISO 10414-1, Petroleum and natural gas industries — Field testing of drilling fluids — Par 1: Water-based 

fluids 

1 

© ISO 2004 – All rights reserved 1 


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ISO 10432:2004(E) 


ISO 10417, Petroleum and natural gas industries — Subsurface safety valve systems — Design, installation, 

operation and redress 

ISO 13628-3, Petroleum and natural gas industries — Design and operation of subsea production systems — 

Part 3: Through flowline (TFL) systems 

ISO 13665, Seamless and welded steel tubes for pressure purposes — Magnetic particle inspection of the 

tube body for the detection of surface imperfections 

ISO 15156 (all parts), Petroleum and natural gas industries — Materials for use in H 2 S-containing 

environments in oil and gas production 

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ISO 16070, Petroleum and natural gas industries — Downhole equipment — Lock mandrels and landing 

nipples 

ISO/IEC 17025, General requirements for the competence of testing and calibration laboratories 

ANSI/NCSL Z540-1:1994, General requirements for calibration laboratories and measuring and test 

equipment 1) 

API Manual of Petroleum Measurement Standards, Chapter 10.4, Determination of sediment and water in 

crude oil by the centrifuge method (field procedure) 2) 

API Spec 5B, Threading, gauging, and thread inspection of casing, tubing, and line pipe threads 

API Spec 14A, Specification for subsurface safety valve equipment 

ASME Boiler and Pressure Vessel Code, Section II, Materials specification 3) 

ASME Boiler and Pressure Vessel Code, Section V, Nondestructive examination 

ASME Boiler and Pressure Vessel Code, Section VIII:2001, Pressure vessels 

ASME Boiler and Pressure Vessel Code, Section IX, Welding and brazing qualifications 

ASTM A 388/A 388M, Standard practice for ultrasonic examination of heavy steel forgings 4) 

ASTM A 609/A 609M, Standard practice for castings, carbon, low-alloy, and martensitic stainless steel, 

ultrasonic examination thereof 

ASTM D 395, Standard test methods for rubber property — Compression set 

ASTM D 412, Standard test methods for vulcanized rubber and thermoplastic elastomers — Tension 

ASTM D 1414, Standard test methods for rubber O-rings 

ASTM D 2240, Standard test methods for rubber propert — Durometer hardness 

ASTM E 94, Standard guide for radiographic examination 

ASTM E 140, Standard hardness conversion tables for metals. (Relationship among Brinell hardness, Vickers 

hardness, Rockwell hardness, superficial hardness, Knoop hardness, and scleroscope hardness) 

1) NCSL International, 2995 Wilderness Place, Suite 107, Boulder, Colorado 80301-5404, USA. 

2) American Petroleum Institute, 1220 L Street NW, Washington, DC 20005-4070, USA. 

3) American Society of Mechanical Engineers, Three Park Avenue, New York, NY 10016-5990, USA. 

4) American Society for Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, PA 19428-2959, USA. 

2 

2 © ISO 2004 – All rights reserved 





ISO 10432:2004(E) 

ASTM E 165, Standard test method for liquid penetrant examination 

ASTM E 186, Standard reference radiographs for heavy-walled [2 to 4 1/2-in. (51 to 114-mm)] steel castings 

ASTM E 280, Standard reference radiographs for heavy-walled [4 1/2 to 12-in. (114 to 305-mm)] steel 

castings 

ASTM E 428, Standard practice for fabrication and control of steel reference blocks used in ultrasonic 

inspection 

ASTM E 446, Standard reference radiographs for steel castings up to 2 in. (51 mm) in thickness 

ASTM E 709, Standard guide for magnetic particle examination 

BS 2M 54:1991, Temperature control in the heat treatment of metals 5) 

SAE-AMS-H-6875:1998, Heat treatment of steel raw materials 6) 

3 Terms and definitions 

For the purposes of this document, the terms and definitions given in ISO 9000:2000 and the following apply. 

3.1 

bean 

orifice 

designed restriction causing the pressure drop in velocity-type SSCSVs 

3.2 

design acceptance criteria 

defined limits placed on characteristics of materials, products, or services established by the organization, 

customer, and/or applicable specifications to achieve conformity to the product design 

[ISO/TS 29001:2003] 

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3.3 

design validation 

process of proving a design by testing to demonstrate conformity of the product to design requirements 

[ISO/TS 29001:2003] 

3.4 

design verification 

process of examining the result of a given design or development activity to determine conformity with 

specified requirements 

[ISO/TS 29001:2003] 

3.5 

end connection 

thread or other mechanism providing equipment-to-tubular interface 

3.6 

environment 

set of conditions to which the product is exposed 

5) BSI, Customer Services, 389 Chiswick High Road, London W4 4AL, UK. 

6) SAE International, 400 Commonwealth Drive, Warrendale, PA 15096-0001, USA. 



3 



ISO 10432:2004(E) 


3.7 

failure 

any equipment condition that prevents it from performing to the requirements of the functional specification 

3.8 

fit 

geometric relationship between parts 

NOTE 

This includes the tolerance criteria used during the design of a part and its mating parts, including seals. 

3.9 

form 

essential shape of a product including all its component parts 

3.10 

function 

operation of a product during service 

3.11 

functional test 

test performed to confirm proper operation of equipment 

3.12 

heat treatment 

heat treating 

alternate steps of controlled heating and cooling of materials for the purpose of changing mechanical 

properties 

3.13 

interchangeable 

conforming in every detail, within specified tolerances, to both fit and function of a safe design but not 

necessarily to the form 

3.14 

manufacturer 

principal agent in the design, fabrication and furnishing of equipment, who chooses to comply with this 

International Standard 

3.15 

manufacturing 

process and action performed by an equipment supplier/manufacturer that are necessary to provide finished 

component(s), assembly(ies) and related documentation, that fulfil the requests of the user/purchaser and 

meet the standards of the supplier/manufacturer 

NOTE Manufacturing begins when the supplier/manufacturer receives the order and is completed at the moment the 

component(s), assembly(ies) and related documentation are surrendered to a transportation provider. 

[ISO 16070] 

3.16 

mass loss corrosion 

weight loss corrosion (deprecated term) 

loss of metal in areas exposed to fluids which contain water or brine and carbon dioxide (CO 2 ), oxygen (O 2 ) or 

other corrosive agents 

NOTE 

The term “weight” is commonly incorrectly used to mean mass, but this practice is deprecated. 

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4 






ISO 10432:2004(E) 

3.17 

model 

SSSV equipment with unique components and operating characteristics which differentiate it from other SSSV 

equipment of the same type 

NOTE 

The same model can have any of a variety of end connections. 

3.18 

operating manual 

publication issued by the manufacturer which contains detailed data and instructions related to the design, 

installation, operation and maintenance of equipment 

3.19 

profile 

feature that is designed for the reception of a locking mechanism 

3.20 

proof test 

test specified by the manufacturer which is performed to verify that the SSSV meets those requirements of the 

technical specification which are relevant to the validation testing performance 

3.21 

qualified part 

part manufactured under a recognized quality assurance programme and, in the case of replacement, 

produced to meet or exceed the performance of the original part produced by the original equipment 

manufacturer (OEM) 

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NOTE 

ISO 9001 is an example of a recognized quality assurance programme. 

[ISO 10417] 

3.22 

redress 

any activity involving the replacement of qualified parts 

cf. repair (3.23) 

NOTE 

See Clause 8 for more information. 

3.23 

repair 

any activity beyond the scope of redress that includes disassembly, re-assembly, and testing with or without 

the replacement of parts and may include machining, welding, heat treating or other manufacturing 

operations, that restores the equipment to its original performance 

cf. redress (3.22) 

[ISO 10417] 

NOTE 

See Clause 8 for more information. 

3.24 

sealing device 

device preventing contact of liquid and/or gas across the interface between the lock mandrel and the landing 

nipple 

3.25 

size 

relevant dimensional characteristics of the equipment as defined by the manufacturer 



5 



ISO 10432:2004(E) 


3.26 

sour service 

exposure to oilfield environments that contain H 2 S and can cause cracking of materials by the mechanisms 

addressed in ISO 15156 

NOTE Adapted from ISO 15156-1:2001. 

3.27 

special feature 

specific component or sub-assembly that provides a functional capability that is not validated during the 

validation test conducted in accordance with 6.5 

3.28 

subsurface safety valve 

SSSV 

device whose design function is to prevent uncontrolled well flow when closed 

NOTE SSSVs can be installed and retrieved by wireline or pump-down methods (wireline-retrievable) or be an integral 

part of the tubing string (tubing-retrievable). 

3.29 

subsurface safety valve equipment 

SSSV equipment 

subsurface safety valve, and all components that establish tolerances and/or clearances which can affect its 

performance or interchangeability 

3.30 

stress corrosion cracking 

SCC 

cracking of metal involving anodic processes of localized corrosion and tensile stress (residual and/or applied) 

in the presence of water and H 2 S 

NOTE Chlorides and/or oxidants and elevated temperature can increase the susceptibility of metals to this 

mechanism of attack. 

[ISO 15156-1] 

3.31 

stress cracking 

stress corrosion cracking, or sulfide stress cracking, or both 

NOTE Adapted from NACE MR0175: Jan 2003. 

3.32 

stress relief 

controlled heating of material to a predetermined temperature for the purpose of reducing any residual 

stresses 

3.33 

sulfide stress cracking 

SSC 

cracking of metal involving corrosion and tensile stress (residual and/or applied) in the presence of water and 

H 2 S 

NOTE SSC is a form of hydrogen stress cracking (HSC) and involves embrittlement of the metal by atomic hydrogen 

that is produced by acid corrosion on the metal surface. Hydrogen uptake is promoted in the presence of sulfides. The 

atomic hydrogen can diffuse into the metal, reduce ductility and increase susceptibility to cracking. High strength metallic 

materials and hard weld zones are prone to SSC. 

[ISO 15156-1] 

6 

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ISO 10432:2004(E) 

3.34 

test agency 

organization which provides a test facility and administers a test program that meets the validation test 

requirements of this International Standard 

NOTE 

See Annex A for test agency requirements. 

3.35 

test pressure 

pressure at which the equipment is tested based upon all relevant design criteria 

3.36 

test section 

test apparatus which contains the SSSV and provides for connection to a test facility's validation test 

apparatus 

3.37 

type 

SSSV equipment with unique characteristics which differentiate it from other functionally similar SSSV 

equipment 

EXAMPLES 

SCSSV, velocity-type SSCSV and low-tubing-pressure-type SSCSV are types of SSSV. 

3.38 

validation test 

test performed to qualify a particular size, type and model of equipment for a specific class of service 

NOTE 

See Annex B for details. 

3.39 

working pressure 

SSSV internal pressure rating, including the differential rating with the valve closed 

4 Abbreviated terms 

AQL 

NDE 

TFL 

SCSSV 

SSCSV 

SSSV 

TRSV 

WRSV 

acceptance quality limit 

non-destructive examination 

through flowline 

surface-controlled subsurface safety valve 

subsurface controlled subsurface safety valve 

subsurface safety valve 

tubing-retrievable safety valve 

wireline-retrievable safety valve 



7 



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ISO 10432:2004(E) 


5 Functional specification 

5.1 General 

5.1.1 Functional requirements 

The user/purchaser shall prepare a functional specification for ordering products which conform with this 

International Standard and specify the following requirements and operating conditions, as appropriate, and/or 

identify the supplier's/manufacturer's specific product. These requirements and operating conditions may be 

conveyed by means of a dimensional drawing, data sheet or other suitable documentation. 

5.1.2 Classes of service 

SSSV equipment manufactured in accordance with this International Standard shall conform to one or more of 

the following classes of service. The user/purchaser shall specify the class(s), as applicable. 

⎯ 

⎯ 

⎯ 

Class 1: standard service. This class of SSSV equipment is intended for use in wells which are not 

expected to exhibit the detrimental effects defined by Classes 2, 3, or 4. 

Class 2: sandy service. This class of SSSV equipment is intended for use in wells where particulates 

such as sand could be expected to cause SSSV equipment failure. 

Class 3: stress cracking service. This class of SSSV equipment is intended for use in wells where 

water containing corrosive agents can cause stress cracking. Class 3 equipment shall meet the 

requirements for Class 1 or Class 2 service and be manufactured from metallic materials that are 

demonstrated as resistant to sulfide stress cracking and stress corrosion cracking. 

NOTE 

⎯ 

The supplier/manufacturer shall ensure that the metallic materials used in Class 3 equipment meet the 

metallurgical requirements of ISO 15156 (all parts) for sour service and/or shall be suitable for service in 

non-sour-containing environments where stress corrosion cracking can occur. 

The user/purchaser shall ensure that the specific metallic materials contained within Class 3 equipment 

are suitable for the intended application. 

Within Class 3, there are two sub-classes, as follows: 

1) 3S for sulfide stress cracking service and stress corrosion cracking service in which chlorides are 

present in a sour environment. Metallic materials suitable for a 3S environment shall be in 

accordance with ISO 15156 (all parts). 

2) 3C for stress corrosion cracking service in a non-sour environment. Metallic materials suitable for 

Class 3C non-sour service are dependent on specific well conditions; no national or international 

standards exist for the application of metallic materials for this class of service. 

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For the purposes of these provisions, NACE MR0175/ISO 15156-1-2-3, is equivalent to ISO 15156 (all parts). 

Class 4: mass loss corrosion service (see 3.16). This class of SSSV equipment is intended for use in 

wells where corrosive agents could be expected to cause mass loss corrosion. Class 4 equipment shall 

meet the requirements for Class 1 or Class 2 and be manufactured from materials which are resistant to 

mass loss corrosion. Metallic materials suitable for Class 4 service are dependent on specific well 

conditions; no national or international standards exist for the application of metallic materials for this 

class of service. 

5.2 SSSV functional characteristics 

The SSSV functional characteristics should include but are not limited to the following: 

a) type of SSSV control (surface-controlled, subsurface-controlled); 

b) type of SSSV retrieval (tubing-retrievable, WL-retrievable, coil-tubing-retrievable, TFL-retrievable, etc.); 

8 






ISO 10432:2004(E) 

c) type of SSSV closing mechanism (ball, flapper, etc.); 

d) requirement for internal self-equalizing capability; 

e) requirement, if any, for holding the SCSSV open without the use of the primary operating source 

(temporary or permanent lock-open system); 

f) requirement, if any, for providing control fluid communication from the SCSSV to any other subsurface 

device (e.g. a through-tubing retrievable secondary valve); 

g) requirement, if any, for providing pump-through capability; 

h) requirement, if any, for a redundant/independent back-up operating system; 

i) requirements, if any, for minimal leakage (in accordance with 6.7.2) during functional testing. 

5.3 Well parameters 

The following characteristics shall be specified as applicable: 

a) well location (land, platform, subsea); 

b) size, mass, grade and material of the casing and tubing; 

c) setting depth (maximum required for application) and control system parameters (control fluid 

type/properties, supply pressure, supply line(s) and connection rating(s), etc.); 

d) casing and/or tubing architecture, trajectory, deviations, maximum dog leg severity; 

e) restrictions through which the SSSV shall pass and restrictions/profiles through which the SSSV service 

tools/accessories shall pass; 

f) requirement, if any, for passage of additional lines (electrical, hydraulic), between the valve OD and the 

casing ID, if applicable. 

5.4 Operational parameters 

5.4.1 SSSVs 

The following operational parameters, as applicable, shall be specified for the SSSV: 

a) rated working pressure; 

b) rated temperature range; 

c) if applicable, maximum allowable pressure drop at maximum flow rate through SSSV; 

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d) loading conditions, including combined loading (pressures, tension/compression, torque, bending) and 

the corresponding temperature extremes anticipated to be applied to the valve; 

e) well stimulation operations, including its parameters, such as acidizing (give the composition of the acid), 

the pressure, the temperature, the acid flow rate and the exposure time, as well as any other chemicals 

used during the stimulation; 

f) sand consolidation and fracturing operations, including sand/proppant description, fluid flow rate, 

proppant/fluid ratio or sand/fluid ratio, chemical composition, pressure and temperature; 

g) well-servicing activities through the safety valve: size, type and configuration of other devices to be run 

through the valve, if applicable. 



9 



ISO 10432:2004(E) 


5.4.2 SSCSVs 

The conditions under which the SSCSV will operate (flow conditions) and the conditions under which the valve 

should close (see ISO 10417) shall be specified, such as 

a) at valve setting depth, the minimum, maximum and normal values of the production/injection pressures 

and temperatures at the anticipated flow rates; 

b) composition of the production fluid (gas/oil/water) and density of each component. 

5.5 Environmental compatibility 

The following shall be identified for the SSSV to ensure environmental compatibility: 

a) production/injection/annulus fluid chemical and physical composition, including solids (sand production, 

scale, etc.), to which the SSSV is exposed during its full life cycle; 

b) in cases where the user/purchaser has access to corrosion-property historical data and/or research which 

is applicable to the functional specification, the user/purchaser should state to the manufacturer which 

material(s) has the ability to perform as required within a similar corrosion environment. 

5.6 Compatibility with related well equipment 

The following information, as applicable, shall additionally be specified to ensure the compatibility of the SSSV 

with the related well equipment: 

a) SSSV size, type, material, the configuration of the interface connections (these connections are not 

included in the evaluation of combined loading); 

b) internal receptacle profile(s), sealing bore dimension(s), outside diameter, inside diameter and their 

respective locations; 

c) requirement(s) for passage of conduits (electrical/hydraulic) between valve OD and casing ID. 

6 Technical specification 

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6.1 Technical requirements 

The supplier/manufacturer shall prepare and provide to the user/purchaser the technical specification that 

responds to the requirements defined in the functional specification. 

6.2 Technical characteristics of SSSV 

The following criteria shall be met: 

a) the SSSV shall be located and/or seal at the specified location and remain so until intentional intervention 

defines otherwise; 

b) while installed, the SSSV shall perform in accordance with the functional specification; 

c) where applicable, the SSSV shall not compromise well-intervention operations as specified in 5.4; 

d) while in service, the SSSV shall meet the requirements of the functional specification. 

10 






ISO 10432:2004(E) 

6.3 Design criteria 

6.3.1 General 

SSSV design shall permit prediction and repeatability of rates, pressures or other conditions required for 

closure. 

6.3.2 Design requirements 

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6.3.2.1 Documentation of designs shall include methods, assumptions, calculations and design 

requirements. Design requirements shall include but not be limited to those criteria for size, test, working and 

operating pressures, materials, environment (temperature limits, service class, chemicals) and other pertinent 

requirements upon which the design is based. Design documentation shall be reviewed and verified by a 

qualified individual other than the individual who created the original design. 

6.3.2.2 SSSV equipment conforming to this International Standard shall be manufactured to drawings 

and specifications that are substantially the same as those of the size, type, and model SSSV equipment that 

has passed the validation test. 

6.3.2.3 The manufacturer shall establish verified internal yield pressure, collapse pressure and minimum 

tensile strength, temperature limits, and rated working pressure, excluding end connections. The manufacturer 

shall identify the critically stressed components of the product and the mode of stress. The manufacturer shall 

calculate the critical stress level in the identified component(s) based upon the maximum loads in the design 

input requirements. The minimum acceptable material condition and minimum acceptable material yield shall 

be used in the calculations and the calculations shall include consideration of temperature limit effects and 

thermal cycles. Metal mechanical properties de-rating shall be in accordance with ASME Boiler and Pressure 

Vessel Code, Section II, Part D. 

The design shall take into account the effects of pressure containment and pressure-induced loads. 

Specialized conditions shall also be considered such as pressure testing with temporary test plugs. 

6.3.2.4 Component and subassembly identification and interchangeability shall be required within each 

manufacturer's service class, size, type and model, including working pressure rating of SSSV equipment. 

Additive dimensional tolerances of components shall be such that proper operation of the SSSV equipment is 

assured. This requirement applies to manufacturer-assembled equipment and to replacement components or 

sub-assemblies. 

6.3.2.5 TRSV profiles that interface with locks and sealing devices covered by ISO 16070 shall comply 

with the requirements of that International Standard. 

6.3.3 Working pressure de-rating 

6.3.3.1 Working pressure de-rating of SSSVs of the same nominal size, type and model is permitted by 

reference to a successfully validation-tested product (base design) when the requirements of this subclause 

and this International Standard are satisfied. The rated working pressure of a de-rated design may be less 

than that of the base design by a maximum of 50 %. 

6.3.3.2 In establishing a de-rated design, the manufacturer shall identify the critically stressed 

components of the base design, establish the maximum stress factors within those components at the 

maximum rated conditions and the specific mode of that stress. All design considerations and stress factors 

applied to the base design and its components shall be applied to the de-rated design evaluation. 

The manufacturer shall establish the maximum stress factors in the equivalent components within the de-rated 

design. The minimum acceptable material condition, minimum acceptable material yield strengths, and 

maximum and minimum temperature effects on material properties shall be used. 

6.3.3.3 Evaluation of the de-rated design shall include comparison of the calculated maximum stress 

factors stated as a percentage of material yields of the components of the base design; these shall not exceed 



11 



ISO 10432:2004(E) 


the maximum stress factors of the components of the base design. The mode of stress and same method of 

calculation(s)/evaluation(s) shall be applied to the identified components of both product designs. 

Adjustments to material thickness or yield strengths shall not negatively impact maximum stress factors. The 

de-rated product shall be evaluated by the manufacturer to ensure that it will meet the requirements of the 

validation test. 

6.3.3.4 Each de-rated product requires evaluation, justification and design documentation of the changes. 

Documentation shall be included in the product's design records. 

6.3.4 Materials 

6.3.4.1 General 

a) Materials, and/or the service, shall be stated by the supplier/manufacturer and shall be suitable for the 

class of service and the environment specified in the functional specification. The manufacturer shall have 

written specifications for all materials. All materials used shall comply with the manufacturer's written 

specifications. 

b) The user/purchaser may specify materials for the specific corrosion environment in the functional 

specification. Should the manufacturer propose to use another material, the manufacturer shall state that 

this material has performance characteristics suitable for all parameters specified in the well and 

production/injection parameters. This applies to metallic and non-metallic components. 

c) Material substitutions in qualified SSSV equipment are allowed without validation testing provided that the 

manufacturer's selection criteria are documented and meet all other requirements of this International 

Standard. 

6.3.4.2 Metals 

6.3.4.2.1 The manufacturer's specifications shall define the following: 

a) chemical-composition limits; 

b) heat treatment conditions; 

c) mechanical-property limits: 

1) tensile strength, 

2) yield strength, 

3) elongation, 

4) hardness. 

6.3.4.2.2 The mechanical properties specified in 6.3.4.2.1 c) for traceable metal components shall be 

verified by tests conducted on a material sample produced from the same heat of material. The material 

sample shall experience the same heat treatment process as the component it qualifies. Material 

subsequently heat-treated from the same heat of material shall be hardness-tested after processing to confirm 

compliance with the hardness requirements of the manufacturer's specifications. The hardness results shall 

verify through documented correlation that the mechanical properties of the material tested meet the 

properties specified in 6.3.4.2.1.c). The heat treatment process parameters shall be defined in the heat 

treatment procedure. Hardness testing is the only mechanical-property test required after stress relieving. 

Material test reports provided by the material supplier or the manufacturer are acceptable documentation. 

6.3.4.2.3 Each welded component shall be stress-relieved as specified in the manufacturer's written 

specifications and, where applicable, in accordance with paragraphs UCS-56 and UHA-32, Section VIII, 

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ISO 10432:2004(E) 

Division 1, Subsection C, ASME Boiler and Pressure Vessel Code. In addition, carbon and low-alloy steel 

weldments on Class 3S SSSV equipment shall be stress-relieved in accordance with ISO 15156 (all parts). 

NOTE 

For the purposes of these provisions, NACE MR0175/ISO 15156-1-2-3, is equivalent to ISO 15156 (all parts). 

6.3.4.3 Non-metals 

6.3.4.3.1 The manufacturer shall have documented procedures, including acceptance criteria, for 

evaluations or testing of sealing materials or other non-metals to the limits for which the equipment is rated. 

6.3.4.3.2 Evaluations (or tests) shall verify the material used is suitable for use in the specific configuration, 

environment and application. These evaluations shall include the combination of: pressure, temperature, 

geometric seal design and its application, and the fluids compatible with the intended application. 

6.3.4.3.3 Sealing devices and materials previously qualified in accordance with prior editions of ISO 10432 

or API Spec 14A for the relevant range of application shall be considered as meeting the design validation 

requirements of this International Standard. 

6.3.4.3.4 The manufacturer's written specifications for non-metallic compounds shall include handling, 

storage and labelling requirements, including the cure date, batch number, compound identification and shelf 

life appropriate to each compound and shall define those characteristics critical to the performance of the 

material, such as the following: 

a) compound type; 

b) mechanical properties, as a minimum: 

1) tensile strength (at break), 

2) elongation (at break), 

3) tensile modulus (at 50 % or 100 %, as applicable); 

c) compression set; 

d) durometer hardness. 

6.3.5 Performance data 

6.3.5.1 Performance rating-SCSSV 

The supplier/manufacturer shall state the pressure, temperature and axial load rating, as applicable for the 

specific product. This information may be provided in an operating performance envelope; an example is 

given in Annex E. 

6.3.5.2 Performance rating-SSCSV 

The supplier/manufacturer shall provide the following information, as applicable, to establish the closing 

conditions for the specific product: 

a) orifice size; 

b) setting spring; 

c) number of spacers to be used; 

d) pressure charge. 



13 

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ISO 10432:2004(E) 


6.3.6 TFL equipment 

For additional requirements for these products in TFL applications, see ISO 13628-3. 

6.4 Design verification 

Design verification shall be performed to ensure that each SSSV design meets the supplier's/manufacturer's 

technical specifications. Design verification includes activities such as design reviews, design calculations, 

physical tests, comparison with similar designs and historical records of defined operating conditions. 

6.5 Design validation 

6.5.1 General 

The SSSVs produced in accordance with this International Standard shall pass the validation test required by 

this subclause. 

a) SSSVs shall pass the applicable validation test specified in Annex B and shall be performed by a test 

agency. 

b) Seals shall meet the requirements of 6.3.4.3. 

The validation testing requirements in this International Standard are not represented as well conditions. 

The objectives of the validation testing requirements of this subclause are to qualify SSSV equipment for 

specific classes of service, either Class 1 or Class 2. SSSV equipment furnished to this International Standard 

requires validation testing to qualify each size, type and model of SSSV. Qualification for Class 2 service shall 

include testing for Class 1 service. An SSSV passing the Class 1 portion, but failing the Class 2 portion of the 

combined test, shall be qualified for Class 1 service only. 

Successful completion of the validation testing process shall qualify SSSVs of the same size, type and model 

as the tested SSSV. 

Substantive changes to the validation test (specified herein) shall require requalification of a previously 

qualified SSSV within three years of the effective date of the change. 

With mutual consent between the test agency and the manufacturer, higher flow rates than those stipulated in 

Annex B may be applied and used for all flow tests. 

6.5.2 Manufacturer requirements 

a) The SSSV shall be proof tested to ensure the valve meets the requirements of the technical specification 

with the manufacturer's specified safety factors. The manufacturer shall provide the test agency with an 

SSSV of most recent manufacture, one operating manual, records of proof testing, and associated 

documentation for each size, type and model for the class of service and working pressure desired in the 

validation test. 

b) The manufacturer shall maintain a validation test file on each validation test including any retests that 

may have been required to qualify SSSV equipment and seals. This file shall be retained by the 

manufacturer for a period of ten years after such SSSV equipment and seals are discontinued from the 

manufacturer's product line. 

c) The manufacturer shall furnish any equipment not normally furnished by the test agency to accommodate 

installation of a particular SSSV in the test facility or to accomplish the validation test. 

d) The manufacturer shall submit a validation test application for each SSSV to be validation tested to the 

test agency that shall contain the manufacturer's test application as required in A.1. 

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14 






ISO 10432:2004(E) 

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e) In the event that a particular SSSV has design or operational features which are incompatible with the 

test facility and test procedures required by this International Standard, the manufacturer shall advise the 

test agency as to the nature of the incompatibility and shall request and fully describe on the test 

application, or attachments thereto, any equipment or procedures required to test the SSSV. 

Responsibility for furnishing, installing and testing this equipment shall be by agreement between the test 

agency and the manufacturer. The manufacturer shall be responsible for assuring that such equipment or 

procedures are not less stringent than this International Standard. 

f) In the case of validation test non-conformance, the manufacturer shall be responsible for determining the 

cause of the non-conformance. The test agency shall cooperate with the manufacturer to determine 

whether the non-conformance was product or test agency related. If the nonconformance is determined to 

be valve-related, the nonconformance becomes a test failure; if the nonconformance is determined to be 

test agency related, the manufacturer and test agency shall determine a course of action on the validation 

test process for the specific valve that is not less stringent than the validation testing requirements of this 

International Standard. The test agency shall document the testing non-conformance on the test data 

forms. 

g) If a particular size, type and model of SSSV fails the validation test, that SSSV and any other SSSV of the 

same basic design and materials of construction shall not be submitted for retest until the manufacturer 

has determined and documented the justification for retest. The manufacturer shall conduct this analysis 

and document the results, including any corrective action taken. Such information need not be submitted 

to the test agency, but shall be placed in the manufacturer's test file for that SSSV before the SSSV is 

submitted for retest. 

h) Pre-test and post-test dimensional verification of functionally critical dimensions defined by the 

manufacturer shall be conducted and documented by the manufacturer. Dimensions shall be within 

established criteria. 

6.5.3 Test agency requirements 

Test agency requirements are provided in Annex A. 

6.5.4 Special feature validation 

The manufacturer shall identify, in design documentation, all special features included in the product design 

that are not validated by design validation testing per this International Standard. Special features shall be 

validated by test to their rated limits. Special feature validation testing may be performed by the manufacturer. 

The manufacturer shall identify those special features that shall be included in the functional testing. 

The manufacturer's design validation documentation shall include the design requirements, test procedures 

and test results of special features. 

6.6 Design changes 

Changes to the design acceptance criteria of the SSSV design which may affect validation test performance 

or interchangeability shall require requalification of the SSSV design. Seals that meet the requirements of 

6.3.4.3 shall be considered interchangeable among the SSSV equipment of any one manufacturer. 

The manufacturer/supplier shall, as a minimum, consider the following when making design changes: stress 

levels of the modified or changed components; material changes; and functional changes. All design changes 

and modifications shall be identified, documented, reviewed and approved before their implementation. 

Design changes and changes to design documents shall require the same control features as the design 

which has passed the applicable validation test requirements of this International Standard. 

6.7 Functional test 

6.7.1 Each SSSV shall be tested in accordance with Annex C. 

6.7.2 Optional minimal leakage requirements are given in Annex D. 



15 



ISO 10432:2004(E) 


7 Supplier/manufacturer requirements 

7.1 General 

Clause 7 contains the detailed requirements to verify that each product manufactured under this International 

Standard meets the requirements of the functional and technical specifications. 

7.2 Raw material 

7.2.1 Certification 

Raw material used in the manufacture of components shall require the following: 

a) certificate of conformance stating that the raw material meets the manufacturer's documented 

specifications; 

b) material test report so that the manufacturer can verify that the raw material meets their documented 

specifications. 

7.2.2 Mechanical and physical properties 

7.2.2.1 Metals 

Tensile testing shall be in accordance with ISO 6892 for the metallic materials used for traceable components. 

Hardness testing shall be in accordance with ISO 6506-1 or ISO 6508-1; ISO 6507-1 may be used if 

ISO 6506-1 or ISO 6508-1 cannot be applied due to size, accessibility, or other limitations. Hardness 

conversion to other measurement units shall be in accordance with ASTM E 140, with the exceptions noted in 

ISO 15156 (all parts) for materials that are intended for use in wells where corrosive agents can possibly be 

expected to cause stress-corrosion cracking. 

NOTE 

For the purposes of these provisions, NACE MR0175/ISO 15156-1-2-3 is equivalent to ISO 15156 (all parts). 

7.2.2.2 Non-metals 

Non-metals shall be tested to determine their mechanical properties as follows: 

a) tensile, elongation, modulus: 

1) O-rings in accordance with ASTM D 1414, 

2) other elastomers in accordance with ASTM D 412 (alternative ISO or ASTM methods may be used, 

where applicable), 

3) non-elastomers in accordance with ISO 527-1; 

NOTE For the purposes of these provisions, ASTM D 638 is equivalent to ISO 527-1. 

b) compression set (homogeneous elastomeric compounds only): 

1) O-rings in accordance with ASTM D 1414, 

2) all others in accordance with ASTM D 395; 

c) durometer hardness: 

1) O-rings in accordance with ISO 48 or ASTM D 2240 with Shore M, 

NOTE For the purposes of these provisions, ASTM D 1415 is equivalent to ISO 48. 

16 




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ISO 10432:2004(E) 

2) other elastomers in accordance with ASTM D 2240 (plastics and other materials may be tested using 

the Rockwell method, where applicable). 

7.3 Heat-treating-equipment qualification 

7.3.1 Furnace calibration 

Furnaces for heat treatment of production parts shall require the following. 

a) Heat treatment of production parts shall be performed with heat treating equipment that has been 

calibrated and surveyed. 

b) Each furnace shall have been surveyed within one year prior to heat treating operations. When a furnace 

is repaired or rebuilt, a new inspection shall be required before heat treating. 

c) Batch-type and continuous-type heat treating furnaces shall be calibrated in accordance with one of the 

following procedures: 

1) procedures specified in SAE-AMS-H-6875:1998, Section 4; 

2) procedures specified in BS 2M 54:1991, Section 7; 

3) manufacturer's written specifications including acceptance criteria which are not less stringent than 

the procedures identified above. 

7.3.2 Furnace instrumentation 

The requirements for furnace instrumentation are as follows. 

a) Automatic controlling and recording instruments shall be used. 

b) Thermocouples shall be located in the furnace working zone(s) and protected from furnace atmospheres. 

c) Controlling and recording instruments used for the heat treatment processes shall possess an accuracy 

of ± 1 % of their full-scale range. 

d) Temperature-controlling and -recording instruments shall be calibrated at least once every three months 

until a documented calibration history can be established; calibration intervals shall then be established 

based on repeatability, degree of usage and documented calibration history. 

e) Equipment used to calibrate the production equipment shall possess an accuracy of ± 0,25 % of full-scale 

range. 

7.4 Traceability 

7.4.1 All components, weldments, subassemblies and assemblies of SSSV equipment shall be traceable 

except the following: 

a) setting springs used to establish closure parameters for SSCSVs; 

b) beans for SSCSVs; 

c) common hardware items such as nuts, bolts, set screws and spacers. 

7.4.2 Traceability shall be in accordance with the manufacturer's documented procedures. All assemblies, 

components (including seals), weldments and subassemblies of equipment supplied shall be traceable to a 

job lot and a material test report. Components and weldments shall also have their included heat(s) or batch 

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17 



ISO 10432:2004(E) 


lot(s) identified. All components and weldments in a multi-heat or multi-batch lot shall be rejected if any heat or 

batch does not comply with the manufacturer's specified requirements. 

7.4.3 Traceability for SSSV equipment is considered sufficient if the equipment meets the requirements of 

this International Standard when it leaves the manufacturer's inventory. 

7.5 Components undergoing special processes 

7.5.1 Coatings and overlays 

Application of coatings and overlays shall be controlled using documented procedures and instructions that 

include acceptance criteria. 

7.5.2 Welding and brazing 

Welding and brazing shall require the following. 

a) Welding and brazing procedure and personnel qualification shall be in accordance with ASME Boiler and 

Pressure Vessel Code Section IX. 

b) Material and practices not listed in the ASME Boiler and Pressure Vessel Code Section IX shall be 

applied using weld procedures qualified in accordance with the methods of ASME Boiler and Pressure 

Vessel Code Section IX. 

7.6 Quality control 

7.6.1 General 

Subclause 7.6 provides minimum quality control requirements to meet this International Standard. All quality 

control work shall be controlled by documented instructions that include acceptance criteria. 

7.6.2 Component dimensional inspection 

All traceable components, except non-metallic seals, shall be dimensionally inspected to assure proper 

function and compliance with design criteria and specifications. Inspection shall be performed during or after 

the manufacture of the components but prior to assembly, unless assembly is required for proper 

measurement. 

7.6.3 Non-metals inspection 

a) Sampling procedures and the basis for acceptance or rejection of a batch lot shall be in accordance with 

ISO 2859-1, general inspection level II at a 2,5 AQL for O-rings and a 1,5 AQL for other sealing elements 

until a documented variation history can be established. Sampling procedures shall then be established 

based on the documented variation history. 

b) Visual inspection of O-rings shall be in accordance with ISO 3601-3. Other sealing elements shall be 

visually inspected in accordance with the manufacturer's documented specifications. 

NOTE For the purposes of this provision, MIL STD 413 is equivalent to ISO 3601-3. 

c) Dimensional tolerances of O-rings shall be in accordance with ISO 3601-1. Other sealing elements shall 

meet dimensional tolerances of the manufacturer's written specifications. 

NOTE For the purposes of this provision, SAE AS568B is equivalent to ISO 3601-1. 

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18 






ISO 10432:2004(E) 

d) The durometer hardness of O-rings or other elastomeric sealing elements shall be determined in 

accordance with ISO 48 or ASTM D 2240. A test specimen manufactured from each batch may be used. 

NOTE For the purposes of these provisions, ASTM D 1415 is equivalent to ISO 48. 

7.6.4 Surface inspection(s) 

The supplier/manufacturer shall have documented procedures, including acceptance criteria, for inspection of 

all accessible surfaces for defects and damage before assembly of the SSSV. 

7.6.5 Thread inspection 

7.6.5.1 All API tapered-thread tolerances, inspection requirements, gauging, gauging practice, gauge 

calibration and gauge certification shall be in accordance with API Spec 5B. 

7.6.5.2 All other thread tolerances, inspection requirements, gauging, gauging practice, gauge calibration 

and gauge certification shall conform to the specified thread manufacturer's written specifications. 

7.6.6 Measuring/testing equipment calibration 

7.6.6.1 Measuring and testing equipment used for acceptance shall be identified, inspected, calibrated 

and adjusted at specific intervals in accordance with documented specifications, ANSI/NCSL Z540-1, and this 

International Standard. 

7.6.6.2 Pressure measuring devices shall 

a) be readable to at least ± 0,5 % of full-scale range; 

b) be calibrated to maintain ± 2 % accuracy of full-scale range. 

7.6.6.3 Pressure measuring devices shall be used only within the calibrated range. 

7.6.6.4 Pressure measuring devices shall be calibrated with a master pressure measuring device or a 

dead-weight tester. Calibration intervals for pressure-measuring devices shall be a maximum of three months 

until documented calibration history can be established. Calibration intervals shall then be established based 

on repeatability, degree of usage and documented calibration history. 

7.6.7 NDE 

7.6.7.1 Requirements 

7.6.7.1.1 All NDE instructions shall be approved by a Level III examiner qualified in accordance with 

ISO 9712. 

NOTE For the purposes of these provisions, SNT-TC-1A is equivalent to ISO 9712. 

7.6.7.1.2 All primary closure springs shall be magnetic-particle or liquid-penetrant inspected for surface 

defects to verify conformance with the manufacturer's written specifications. 

7.6.7.1.3 All pressure-containing welds shall be magnetic-particle or liquid-penetrant inspected for surface 

defects and shall be volumetrically inspected by radiographic or ultrasonic techniques to verify conformance 

with the manufacturer's written specifications. 

7.6.7.1.4 All pressure-containing castings and forgings shall be magnetic-particle or liquid-penetrant 

inspected for surface defects and shall be volumetrically inspected by radiographic or ultrasonic techniques to 

verify conformance with the manufacturer's written specifications. The manufacturer may develop AQL 

inspection levels based on documented variation history. 



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19 



ISO 10432:2004(E) 


7.6.7.2 Methods and acceptance criteria 

7.6.7.2.1 Liquid penetrant 

Liquid-penetrant inspection shall be carried out as follows: 

a) method: in accordance with ASTM E 165; 

b) acceptance criteria: in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, 

Appendix 8. 

7.6.7.2.2 Wet magnetic particle examination 

Wet magnetic particle examination shall be carried out as follows: 

a) method: in accordance with ISO 13665 or ASTM E 709; 

b) indications shall be described as one of the following: 

1) relevant indication: only those indications with major dimensions greater than 1,6 mm (1/16 in) shall 

be considered relevant whereas inherent indications not associated with a surface rupture (i.e., 

magnetic permeability variations, non-metallic stringers etc.) shall be considered non-relevant; 

2) linear indication: any indication in which the length is equal to or greater than three times its width; 

3) rounded indication: any indication which is circular or elliptical in which the length is less than three 

times its width; 

c) acceptance criteria: 

1) any relevant indication greater than or equal to 4,8 mm (3/16 in) shall be considered unacceptable; 

2) no relevant linear indications shall be allowed for weldments; 

3) no more than ten relevant indications shall be present in any 39 cm 2 (6 in 2 ) area; 

4) four or more rounded relevant indications in a line separated by less than 1,6 mm (1/16 in) shall be 

considered unacceptable. 

7.6.7.2.3 Ultrasonic inspection of weldments 

Ultrasonic inspection of weldments shall be carried out as follows: 

a) method: in accordance with ASME Boiler and Pressure Vessel Code, Section V, Article 5; 

b) acceptance criteria: in accordance with ASME Boiler and Pressure Code, Section VIII, Division 1, 

Appendix 12. 

7.6.7.2.4 Ultrasonic inspection of castings 

Ultrasonic inspection of castings shall be carried out as follows: 

a) method: in accordance with ASTM E 428 and ASTM A 609; 

b) acceptance criteria: in accordance with ASTM A 609 at an ultrasonic testing quality level 1, minimum. 

20 

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ISO 10432:2004(E) 

7.6.7.2.5 Ultrasonic inspection of forgings and wrought products 

Ultrasonic inspection of forgings and wrought products shall be carried out as follows: 

a) method: in accordance with ASTM E 428 and ASTM A 388; 

b) calibration: 

1) back reflection technique: the instrument shall be set so that the first back reflection is 75 % ± 5 % of 

the screen height when the transducer is placed on an indication-free area of the forging or wrought 

product, 

2) flat bottom hole technique: the distance amplitude curve (DAC) shall be based on a 3,2 mm (1/8 in) 

flat bottom hole for thicknesses up to and including 101,6 mm (4 in) and a 6,4 mm (1/4 in) flat bottom 

hole for thicknesses greater than 101,6 mm (4 in), 

3) angle beam technique: the distance amplitude curve (DAC) shall be based on a notch of a depth 

equal to the lesser of 9,5 mm (3/8 in) or 3 % of the normal section thickness [9,5 mm (3/8 in) 

maximum], a length of approximately 25,4 mm (1 in) and a width no greater than twice its depth; 

c) acceptance criteria: any of the following forging or wrought product defects shall be basis for rejection: 

1) back reflection technique: indications greater than 50 % of the referenced back reflection 

accompanied by a complete loss of back reflection, 

2) flat bottom hole technique: indications equal to or larger than the indications observed from the 

calibration flat bottom hole, 

3) angle beam technique: amplitude of the discontinuities exceeding those of the reference notch. 

7.6.7.2.6 Radiographic inspection of weldments 

Radiographic inspection of weldments shall be carried out as follows: 


b) acceptance criteria: in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, 

UW-51. 

7.6.7.2.7 Radiographic inspection of castings 

Radiographic inspection of castings shall be carried out as follows: 


b) acceptance criteria: 

1) in accordance with ASTM E 186; 

2) in accordance with ASTM E 280; 

3) in accordance with ASTM E 446. 

The maximum defect severity levels for 1), 2) and 3) are given in Table 1. 



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ISO 10432:2004(E) 


Table 1 — Maximum defect severity levels for castings 

Defect category 

Maximum defect severity level 

A 3 

B 2 

C (all types) 2 

D 

E 

F 

G 

None acceptable 




NOTE The defect categories, types and severity levels are defined in ASTM E 186, 

ASTM E 280 and ASTM E 446, as applicable. 

7.6.7.2.8 Radiographic inspection of forgings 

Radiographic inspection of forgings shall be carried out as follows: 


b) acceptance criteria of which any of the following defects shall be basis for rejection: 

1) any type of crack or lap; 

2) any other elongated indication with length, L, and wall thickness, t, as follows: 

⎯ L > 6,4 mm (1/4 in) for t u 19 mm (3/4 in) 

⎯ L > 1/3 t for 19 mm < t u 57,2 mm (3/4 in < t u 21/4 in) 

⎯ L > 19 mm (3/4 in) for t > 57,2 mm (21/4 in) 

3) any group of indications in a line that have an aggregate length greater than t in a length of 12 t. 

7.6.8 Personnel qualifications 

7.6.8.1 Personnel performing NDE evaluations and interpretations shall be qualified in accordance with 

ISO 9712, to at least Level II, or equivalent. 


7.6.8.2 Personnel performing visual examinations shall have an annual eye examination, as applicable to 

the discipline to be performed, in accordance with ISO 9712. 

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7.6.8.3 All other personnel performing inspection for acceptance shall be qualified in accordance with 

documented requirements. 

7.6.9 Certifications 

Components undergoing external processes at a subcontractor, such as heat treatment, welding or coating 

shall require the following: 

a) a certificate of conformance stating the materials and/or processes meet the manufacturer's documented 

specifications; 

22 






ISO 10432:2004(E) 

b) a material test report, where applicable, to verify the materials and/or processes meet the supplier's 

documented specifications. 

7.6.10 Manufacturing non-conformities 

Processing of non-conformities shall be controlled in accordance with the manufacturer's documented 

procedures. Weld repair shall be restricted to the weld only. 

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7.7 SSSV functional testing 

7.7.1 SSSV functional testing shall be performed by the manufacturer on each new SSSV manufactured in 

accordance with this International Standard. 

7.7.2 Results of the functional test shall be traceable to the valve tested and retained in accordance with 

7.9.1.1. 

7.7.3 Functional-test data shall be recorded, dated and signed by the personnel performing the tests. The 

required data is indicated in F.1.20 or F.1.21, as applicable. 

7.7.4 If the user/purchaser specifies, the optional functional test for minimal leakage the requirements 

given in annex D shall be applied. 

7.8 Product identification 

SSSV equipment furnished to this International Standard shall be permanently identified in accordance with 

the manufacturer's written specifications. Identification shall include the following: 

a) manufacturer's name or trademark; 

b) manufacturer's size and model; 

c) manufacturer's part number; 

d) unique identifying serial number; 

e) rated working pressure; 

f) minimum ID (TRSV only); 

g) class(es) of service designation. 

Class of service designations listed below may be combined to indicate the complete class of service. For 

example, 2,4 indicates sandy and mass loss corrosion service. 

1 — Standard service 

2 — Sandy service 

3S — Stress corrosion cracking service—sour environment 

3C — Stress corrosion cracking service—non-sour environment 

4 — Mass loss corrosion service. 

h) Orifice beans for velocity-type SSCSVs shall be identified by the orifice diameter. 



23 



ISO 10432:2004(E) 


7.9 Documentation and data control 

7.9.1 Retained documentation 


The supplier/manufacturer shall establish and maintain documented procedures to control all documents and 

data that relate to the requirements of this International Standard. These documents and data shall be legible 

and maintained to demonstrate conformance to specified requirements. All documents and data shall be 

retained in facilities that provide an environment that prevents damage, deterioration, or loss. Documents and 

data may be in the form of any type of media, such as hard copy or electronic media. All documents and data 

shall be available and auditable by the user/purchaser; they shall be available within one week of request. 

Documentation shall be retained for a minimum of five years from the date of manufacture. 

7.9.1.2 Design documentation 

Design criteria, verification, and validation documents for each size, type and model, and the information listed 

below, shall be maintained for ten years after date of last manufacture: 

a) functional and technical specifications; 

b) one complete set of drawings, written specifications and standards; 

c) instructions providing methods for the safe assembly and disassembly of the SSSV and stating the 

operations which are permitted and preclude failure and/or non-compliance with the functional and 

performance requirements; 

d) material type, yield strength and connection identification for the actual end connection(s) provided with 

the SSSV; 

e) operating manual; 

f) contents of F.1.20 or F.1.21, as applicable, and F.1.22 are a minimum data requirement for the 

documentation specified in this subclause; 

g) validation test files shall contain sufficient documentation to identify and permit retrieval of 

1) all drawings and specifications applicable at the time of manufacture, 

2) all applications for validation tests or retests, 

3) all design and/or material modifications, or other justification for retest, of SSSV equipment and seals 

which did not pass any validation test, 

4) all test data specified in this subclause. 

7.9.2 Supplied documentation 


SSSVs shall be delivered with a manufacturer's shipping report and an operating manual. F.1.22 contains 

shipping-report requirements for SSSVs. 

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24 






ISO 10432:2004(E) 

7.9.2.2 Operating manual contents 

a) size, type and model; 

b) class(s) of service; 

c) operating data as follows: 

⎯ 

⎯ 

⎯ 

⎯ 

⎯ 

⎯ 

working pressure, 

temperature range, 

internal yield pressure, 

collapse pressure (applies to tubing-retrievable SSSV equipment at maximum rated temperature), 

tensile load strength (applies to tubing-retrievable SSSV equipment at maximum rated temperature), 

operating envelope, if specified by the user/purchaser (see example in Annex E); 

d) dimensional data, including dimensions of drift bar and drift sleeve, if applicable; 

e) calculations as follows: 

⎯ 

⎯ 

SCSSVs — Calculation procedures used to determine maximum fail-safe setting depths, where 

applicable, 

SSCSVs — Orifice coefficients, spring force, optimum operating range of pressure differential for 

velocity-type valves, etc.; 

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f) drawings and illustrations; 

g) parts list with all necessary information for reordering, including manufacturer's contact information; 

h) specific details of functional testing should be included if the test apparatus or procedures are significantly 

different than those included in this International Standard; 

i) running instructions; 

j) pulling instructions; 

k) inspection and testing procedures; 

l) installation and operating procedures; 

m) troubleshooting and maintenance procedures; 

n) repair limitations; 

o) redress disassembling and reassembling requirements; 

p) operating requirements as follows: 

⎯ 

SCSSVs: 

1) opening and closing procedures with opening and closing pressures, 

2) equalizing procedure, including maximum recommended unequalized opening pressure, 

⎯ 

SSCSVs: 



25 



ISO 10432:2004(E) 


3) opening or equalization procedures, 

4) optimum conditions to avoid nuisance closures and throttling; 

q) Storage recommendations. 

7.10 Failure reporting and analysis 

7.10.1 This subclause provides the requirements for processing the user/purchaser provided failure reports 

as defined in ISO 10417. The supplier/manufacturer shall have documented procedures that define the 

actions required. 

7.10.2 Notification of the receipt of a failure report shall be provided to the submitting user/purchaser contact 

within 30 calendar days of the documented receipt at the manufacturer. This notification shall include any data 

collection requests that the manufacturer needs to perform an effective evaluation and a projected completion 

date of the evaluation. Should the requested data or equipment not be provided as requested, the failure 

report becomes inactive 30 calendar days after the notification has been provided to the user/purchaser. 

7.10.3 Following receipt of the requested data and equipment to be analyzed, reasonable efforts shall be 

implemented to complete the evaluations in a timely manner that meets the prevailing business need. The 

evaluation report shall be provided to the user/purchaser within 15 calendar days after completion of the 

evaluation. This evaluation shall include the actions required of the user/purchaser to mitigate reoccurrence of 

the identified problem and suggested measures to extend the product's operational life, when appropriate. 

The manufacturer shall make necessary design changes that result from the failure analysis on all affected 

SSSV equipment. If the required or suggested actions apply to similar products, they shall be referenced in 

the evaluation. 

7.10.4 Evaluations and any subsequent notifications prepared in response to a failure report shall be 

documented and available for three years after the date of preparation. 

8 Repair/redress 

8.1 Repair 

Repair operations for SSSVs shall include the return of the product to a condition meeting all requirements 

stated in this International Standard or the edition of this International Standard in effect at the time of original 

manufacture. 

8.2 Redress 

Redress operations are beyond the scope of this International Standard. ISO 10417 provides requirements for 

SSSV equipment redress. 

9 Storage and preparation for transport 

9.1 SSSV equipment shall be stored per the written specifications of the equipment manufacturer to prevent 

deterioration (for example, caused by atmospheric conditions, debris, radiation, etc.) prior to transport. 

9.2 SSSV equipment shall be packaged for transport per the written specifications of the equipment 

manufacturer to prevent normal handling loads and contamination from harming the equipment. These 

specifications shall address the protection of: external sealing elements, sealing surfaces, exposed threaded 

connections, access port(s) sealing and contamination from fluids and debris. 

9.3 All material provided as protection for transport shall be clearly identified for removal prior to equipment 

use. 

9.4 For storage after transport, see operating manual. 

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26 






ISO 10432:2004(E) 

Annex A 

(normative) 

Test agency requirements 

A.1 General 

The test agency shall meet the requirements of Annex A and have the ability to perform the tests of Annex B 

in order to conduct validation tests. Any variation from the validation test requirements of this International 

Standard shall be noted on the test application and recorded on the validation test data summary (see F.1.13) 

by the test agency. 

The test agency shall conduct validation tests as specified on the manufacturer's test application in F.1.1 and 

record the results of the validation test as specified in F.1.13. The content of Annex F, as applicable, is a 

minimum data requirement for the documentation specified in this subclause. The test agency shall supply a 

copy of the validation test report to the manufacturer within thirty days of the completion of the test. This report 

shall be retained by the manufacturer and by the test agency, and shall be available to the user/purchaser 

upon request to the manufacturer. 

Test agencies performing validation testing shall conform to ISO/IEC 17025. 

The test agency shall provide, on written request, current documentation to manufacturer or user/purchaser. 

This shall include the following, as a minimum: 

a) description of the facility, including any limitations on the size, length, mass, type, pressure rating, 

temperature rating, and service class of SSSV that may be tested; 

b) test procedures and forms actually used at the facility for each type and service class of SSSV; 

c) procedures for maintenance and calibration of measuring equipment used for test acceptance, and 

calibration records; 

d) procedures for making applications for tests, the delivery of SSSVs, the initial installation and checkout of 

SSSVs and other pertinent information; 

e) any limitations on the accessibility of the facility (such limitations shall not preclude reasonable access to 

the facility for inspection by manufacturers or user/purchasers); 

f) any limitations on the receipt of proprietary information. 

The test agency shall promptly provide a response to the test application requestor, stating acceptance or 

rejection of the requirements therein. A test application may be declined if the data are incomplete, inaccurate 

or self-conflicting. Any declined applications shall detail the specific provisions causing rejection. 

A.2 Test facility requirements 

A.2.1 The components of the test facility systems shall have a capacity and working pressure as required by 

the size and/or working pressure of the SSSV to be tested. Typical test facility schematics, the SSSV gas flow 

facility, the liquid test facility and the controlled-temperature test facility are shown in Figures F.1, F.2, and F.4. 

The control pressure system components shall, as a minimum, consist of the items listed below: 

a) hydraulic-fluid reservoir with a filtered vent; 

b) accumulator; 



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27 



ISO 10432:2004(E) 


c) hydraulic pump; 

d) control system to operate the pump; 

e) pressure relief facility to protect the system. 

A.2.2 There shall be provision for the supply of nitrogen gas to conduct the required nitrogen leak test and a 

gas flow meter to indicate the leakage rate. 

A gas reservoir with a gas release device and instrumentation to measure the test parameters shall be 

provided. 

The test facility shall, as a minimum, consist of the items listed below: 

a) test facility piping, which shall be at least 50,8 mm (2 in) nominal diameter; 

b) fresh-water tank; 

c) sand slurry tank; 

d) Marsh funnel viscometer in accordance with ISO 10414-1 with required timer and graduated beaker; 

NOTE For the purposes of these provisions, API RP 13B1 is equivalent to ISO 10414-1. 

e) centrifuge with basic sediment and water (BS&W) sample flasks in accordance with API Manual of 

Petroleum Measurement, Chapter 10.4; 

f) circulation pumps; 

g) flow meter; 

h) pressure measurement systems; 

i) time-based recorder to simultaneously record the required pressure and flow data; 

j) back-pressure regulator; 

k) propane system as shown in Figure F.5; 

l) high-pressure water pump and accumulator system. 

A.3 Validation test reports 

Test reports completed by a test agency conforming to this International Standard shall be traceable to the 

equipment tested and shall include the following: 

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a) general information (date, location, manufacturer, model, serial number, size, rating, etc.); 

b) summary of test results; 

c) description of the characteristics of equipment under test; 

d) observed data (including calculations and details of test personnel); 

e) test conditions (limits required by the standard); 

f) identification of test methods and procedures; 

28 






ISO 10432:2004(E) 

g) supporting data (log sheets, etc.); 

h) graphical presentation of operating pressure traces; 

i) identification of instruments involved in the testing; 

j) copy of validation test application from F.1.1; 

k) the content of the data requirements of F.1, as applicable; 

l) certificate of compliance in accordance with a national or internationally recognized standard such as 

ISO/IEC Guide 22; 

m) time-based testing data, as requested. 

A.4 Test agency records 

Unless otherwise specified in the appropriate referenced standard(s), the test agency shall keep the following 

records for ten years from completion of all tests on all equipment tested: 

a) test data and test reports, Annex F, as applicable; 

b) measuring and test equipment calibration data; 

c) non-conformance reports; 

d) audit and corrective-action records; 

e) personnel qualification records; 

f) test procedures; 

g) data on any special testing. 

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29 



ISO 10432:2004(E) 


Annex B 

(normative) 

Validation testing requirements 

B.1 General 

To pass the validation test, the SSSV shall successfully complete all steps of the validation-testing procedure 

within the limits specified and in the order shown. 

Validation testing shall be discontinued if the valve fails to perform within the limits specified for any step 

except when such failures are determined to be a result of actions by the test agency or a failure within the 

test facility. The basis for discontinuing the test, and any unusual conditions observed at or prior to the time of 

discontinuance, shall be noted on the test data form by the test agency. 

All pressures are defined as gauge unless otherwise specified and shall be recorded on time-based 

equipment. 

Prior to any liquid pressure test, purge with test liquid to remove air. 

Gas pressure-relieving (bleed-down) operations shall be performed per the manufacturer's requirements. 

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During validation testing of hydraulically operated SSSVs, control line fluid metering may be used to provide a 

readable hydraulic control line pressure trace. Refer to Figure F.6 for a characteristic pressure versus time 

plot for opening and closing hydraulic control pressures with hydraulic fluid being applied at a metered rate. 

When validation testing of SSSV sizes not covered in Tables F.1, F.2, and F.3, the flow rate values may be 

interpolated or extrapolated by a ratio of the square of the diameter versus the parameter involved. 

The test section shall completely enclose a wireline-retrievable SSSV. Tubing-retrievable SSSVs shall be an 

integral part of the test section. The test section shall be rated to at least the rated working pressure of the 

SSSV. 

The test section ends, length and hydraulic control connections shall be compatible with the test agency's 

facility. 

Each data form shall be signed and dated by the person(s) conducting the test. The form containing the data 

specified in F.1.13 shall be signed and dated by the test agency's designated approval authority. 

B.2 Validation test procedure — SCSSV 

B.2.1 General 

Verify that the model and serial numbers appearing on the test valve are in agreement with the manufacturer's 

application. 

B.2.2 Class 1 test 

B.2.2.1 

B.2.2.2 

Perform the SCSSV gas flow test (see B.3). 

Open the test valve. Record the full-open hydraulic control pressure as shown in F.1.4. 

30 






ISO 10432:2004(E) 

B.2.2.3 Fill the test valve with water and circulate water to displace gas out of the test section. Once gas 

has been displaced from the test section, discontinue water circulation. 

B.2.2.4 

B.2.2.5 

B.2.2.6 

B.2.2.7 

B.2.2.8 

B.2.2.9 

B.2.2.10 

B.2.2.11 

B.2.2.12 

B.2.2.13 

B.2.2.14 

B.2.2.15 

Close the test valve. Record the full-closed hydraulic control pressure as shown in F.1.4. 

Perform the liquid leakage test (see B.5). 

Perform the unequalized opening test (see B.6). 

Perform the operating-pressure test (see B.7). 

Perform the propane test (see B.8). 

Perform the nitrogen leakage test (see B.9). 

Repeat the operating-pressure test (see B.7). 

Perform the SCSSV Class 1 flow test (see B.10). 

Repeat B.2.2.9 to B.2.2.11 four additional times. 


Perform the controlled-temperature test (see B.11). 

If the test valve is being qualified for Class 1 service only, proceed to B.2.3.6. 

B.2.3 Class 2 test 

B.2.3.1 

B.2.3.2 

Perform the nitrogen leakage test (see B.9). 

Perform the operating-pressure test (see B.7). 

B.2.3.3 Perform the Class 2 flow test (see B.12). Class 2 flow testing shall be performed in a continuous 

manner with no interruptions longer than 2 h. 

B.2.3.4 

B.2.3.5 

B.2.3.6 

Repeat B.2.3.1 to B.2.3.3 six additional times. 


Perform the drift test (see B.4). 

NOTE If at any point in the Class 2 test the valve fails and it is desired to have Class 1 qualification, perform the 

Class 1 drift test to confirm Class 1qualification. 

B.2.3.7 

B.2.3.8 

If the test valve has performed within the limits specified, it has passed the validation test. 

Summarize the validation test data as specified in F.1.13. 

B.3 Gas flow test — SCSSV 

B.3.1 

Record test data as specified in F.1.2. 

B.3.2 Install the test valve in the gas flow test stand. The test medium shall be air, nitrogen or any other 

suitable gas. 

B.3.3 

Set the control line resistance to the appropriate setting shown in Table F.1. 



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31 



ISO 10432:2004(E) 


⎯ 

⎯ 

⎯ 

The test flow rates specified in Table F.1 are based on a pressure of 13,8 MPa (2 000 psi) and a velocity 

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 

test 2, and a velocity of 3,05 m/s (10 ft/s) for test 3. 

The test flow rates shall be maintained within − 5 % and + 15 % of the nominal value given in Table F.1 or 

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], 

whichever is greater. The low control line resistance test shall be performed with a hydraulic control line 

having an inside diameter of at least 9,6 mm (0,38 in) and a maximum total length of 7,6 m (25 ft). 

The configuration for the high control line resistance test shall consist of the control line used for the 

low-resistance configuration plus a square-edge orifice having an inside diameter of 0,5 mm ± 0,05 mm 

(0,020 in ± 0,002 in) and a length of 25,4 mm ± 2,5 mm (1,0 in ± 0,1 in). 

B.3.4 

Open and close the test valve. Record the full-open and full-closed control pressures. 

B.3.5 Close the flow control valve and bleed valve (see Figure F.1). Set the flow control valve to provide a 

gas flow at a test rate in accordance with Table F.3. 

B.3.6 

B.3.7 

Increase the gas pressure in the system to between 13,8 MPa (2 000 psi) and 17,3 MPa (2 500 psi). 

Open the test valve. Record the full-open control pressure. 

B.3.8 Establish and maintain the gas flow rate indicated in Table F.1, and then close the test valve while 

recording the control line pressure and gas flow rate. 

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 

control pressure reaches zero, or the test valve fails the test. Record the time required by the test valve to 

shut off the specified flow. If the test valve fails, discontinue testing. 

B.3.10 Bleed the valve bore downstream pressure to zero. Adjust the test valve upstream bore pressure to 

8,3 MPa ± 0,4 MPa (1 200 psi ± 60 psi). Record the test valve bore upstream pressure and gas leakage rate. 

If leakage exceeds 0,14 m 3 /min (5 scf/min) of gas, the test valve fails. If the test valve fails, discontinue testing. 

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 

Table F.1 are successfully completed or until the test valve fails. 

B.4 Drift test — SCSSV 

B.4.1 General 

The manufacturer shall provide the test agency with a drift sleeve (for WRSVs) and/or drift bar (for TRSVs and 

WRSVs) that is appropriate for detecting changes in the valve's dimensions. Each drift bar/sleeve shall be 

permanently marked with a unique identifier. Drift bar dimensions (measured) and unique identifier shall be 

recorded along with the minimum specified ID of the test valve (TRSVs and WRSVs) or maximum specified 

OD of the test valve (WRSVs). 

Drift bars shall be of no smaller OD than the valve's specified minimum ID, less 0,75 mm (0,030 in); drift 

sleeves shall be no larger on the ID than the valve's specified maximum OD plus 0,75 mm (0,030 in), and 

shall be a full round at the recorded drift dimensions. 

Each drift bar shall be of a length designated as appropriate to verify that the product provides no restriction to 

the passage of tools for the full length of the product and shall be a minimum length of four times the specified 

inside diameter of the product, or 610 mm (24 in), whichever is greater. 

Each drift sleeve shall be of a length designated as appropriate to verify that the product can be received into 

its intended receptacle and shall be a minimum length of two times the specified outside diameter of the 

product. 

32 

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ISO 10432:2004(E) 

B.4.2 Drift test — TRSV 

B.4.2.1 

B.4.2.2 


Open and close the test valve, recording the full-open hydraulic control pressure. 

B.4.2.3 Orient the test valve so that the valve is vertical, upside down, and in the normal open position. 

The test valve may be opened prior to repositioning. 

B.4.2.4 Pass the drift bar completely through the test valve in a manner that does not cause the test 

valve's closure mechanism to be opened. The drift bar shall be aided by a force no greater than that of gravity 

while being passed down and back through the test valve. If the drift bar does not pass freely completely 

through the test valve, the test valve fails. 

B.4.3 Drift test — WRSV 

B.4.3.1 


B.4.3.2 Open the test valve, recording the full-open hydraulic control pressure. Orient the test valve so 

that the valve is vertical, upside down, and in the normal open position. 

B.4.3.3 Pass the drift bar completely through the test valve in a manner that does not cause the test 

valve's closure mechanism to be opened. The drift bar shall be aided by a force no greater than that of gravity 

while being passed down and back through the test valve. If the drift bar does not pass freely completely 

through the test valve, the test valve fails. 

B.4.3.4 Pass the drift sleeve over the entire length, except for the packing stack/sealing device, of the test 

valve in a manner that does not cause the test valve's closure mechanism to be moved. 

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NOTE 

If control line or control sleeve is in place, a partial drift of the lower valve can be accomplished here. 

Close the test valve and record the closing pressures. If a partial OD drift has been accomplished, pass the 

drift sleeve over the remaining length of the test valve. The drift sleeve shall be aided by a force no greater 

than that of gravity while being passed down and back over the test valve. If the drift sleeve does not freely 

pass completely over the test valve, except for the packing stack/sealing device, the test valve fails. 

B.5 Liquid leakage test — SSSV 

B.5.1 

B.5.2 


Make certain that the test valve is in the closed position with only liquid above and below the valve. 

B.5.3 Apply water pressure upstream of the test valve closure mechanism at 100 % of the rated working 

pressure (allowable range of 95 % to 100 %) of the valve. Record the test valve bore pressure and the time at 

which pressure was applied to the valve. 

B.5.4 Wait for a minimum of 3 min after applying water pressure upstream of the test valve closure 

mechanism before beginning collection of water leakage from the downstream bleed valve. 

Continuously collect water leakage for a period of 5 min. Record the times at which water leakage collection 

began and ended and the amount of water collected. Calculate and record the average leakage rate. If the 

average leakage rate during the collection period exceeds 10 cm 3 /min of water, or if external body leakage is 

detected (tubing-retrievable only), the test valve fails. If the test valve fails, discontinue testing. 



33 



ISO 10432:2004(E) 


B.6 Unequalized opening test — SCSSV 

B.6.1 


B.6.2 Establish water pressure upstream of the test valve closure mechanism at the maximum 

manufacturer-specified opening-pressure differential. 

B.6.3 Open the test valve closure mechanism against pressure as recommended in the test valve-operating 

manual. Record the equalizing pressure and the full-open hydraulic control pressure. 

B.7 Operating-pressure test — SCSSV 

B.7.1 


B.7.2 Apply pressure of 25 % of the rated working pressure (allowable range of 20 % to 30 % of rated 

working pressure) of the test valve to the entire test section. Record the test valve bore pressure (base 

pressure). 

B.7.3 Close and open test valve five times while maintaining the test section pressure recorded in B.7.2 

within the specified range. 

NOTE The test section pressure can increase as the valve is opened, and then can decrease as the valve is closed 

due to the differential volume of the hydraulic operating piston. 

The full-open/full-closed hydraulic control pressures shall be adjusted based on the change in test section 

pressure at the time of control pressure measurement. The adjusted control pressure is determined by 

adding/subtracting the actual control pressure with the difference between the base pressure and the actual 

test section pressure recorded at the time of each opening/closing pressure measurement. If the five adjusted 

hydraulic control pressures do not repeat within ± 10 % of their average, or ± 0,7 MPa (± 100 psi), whichever 

is greater, or if any body joint leakage (tubing-retrievable only) is detected, the test valve fails. 

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 

rated working pressure). 

B.8 Propane test — SCSSV (SSCSV as noted) 

B.8.1 


B.8.2 Open the test valve. Displace liquid out of the test section with nitrogen at a downstream location and 

bleed the nitrogen pressure to zero. 

B.8.3 Cycle the test valve closed and open three times. Leave the test valve open. Record the full-closed 

and full-open hydraulic control pressures. If the three hydraulic control pressures do not repeat within ± 10 % 

of their averages or ± 0,7 MPa (100 psi), whichever is greater, the test valve fails. 

B.8.4 Transfer propane to the test section until the test section pressure reaches 2,8 MPa ± 0,14 MPa 

(400 psi ± 20 psi). 

B.8.5 Open the downstream vent valve until liquid propane is expelled, close the propane vent valve, and 

adjust the pressure to 2,8 MPa ± 0,14 MPa (400 psi ± 20 psi). Record the test valve bore pressure. 

B.8.6 Close and open the test valve three times, leaving the test valve in each position (opened or closed) 

for a minimum of 15 min. Record the full-open and full-closed hydraulic control pressures. 



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34 






ISO 10432:2004(E) 




test section pressure recorded at the time of each opening/closing pressure measurement. If the three 

adjusted hydraulic control pressures do not repeat within ± 10 % of their average, or ± 0,7 MPa (± 100 psi), 

whichever is greater, or if any body joint leakage (tubing-retrievable only) is detected, the test valve fails 

B.8.7 Leave the test valve in the open position in propane for an additional 2 h, minimum. Record the start 

and completion times and the valve bore pressure at the end of the 2 h interval. 

B.8.8 

B.8.9 

Bleed the section pressure to zero. 

Purge the test section with nitrogen. 

B.8.10 Close the test valve and record the full-closed hydraulic control pressure. 

B.9 Nitrogen leakage test — SCSSV (SSCSV as noted) 

B.9.1 


B.9.2 Apply 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) nitrogen pressure upstream of the test valve. Wait a 

minimum of 1 min, then measure any nitrogen leakage through the closure mechanism. Record the test valve 

bore pressure, the leakage rate and the start and completion times of the waiting period. If the leakage rate is 

greater than 0,14 m 3 /min (5 scf/min), or if any body joint leakage (tubing-retrievable only) is detected, the test 

valve fails. 

B.9.3 Repeat B.9.2 at 25 % of the rated working pressure (allowable range of 20 % to 30 % of rated working 

pressure) of the test valve. 

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B.9.4 

B.9.5 

Bleed the pressure upstream of the test valve to zero. 

Open the test valve. Record the full-open hydraulic control pressure. 

B.10 Class 1 flow test — SCSSV 

B.10.1 Record test data as specified in F.1.10. 

B.10.2 Circulate fresh water through the system while bypassing the test valve until gas has been displaced 

from the system. 

B.10.3 Adjust the water flow rate through the test valve to obtain a stable flow at the value specified in 

Table F.2. Record the time at which flow is directed through the test valve. Pass water through the test valve 

at the specified rate for a minimum of 5 min. 

B.10.4 Close the test valve against the flow. Record the full-closed hydraulic control pressure and the water 

flow rate through the test valve at the time closure was initiated. The test valve shall shut off a minimum of 

95 % of the specified flow at the first closure attempt in 15,0 s or less after the hydraulic control pressure 

reaches zero, or the test valve fails. Record the time required by the test valve to shut off the specified flow. 

B.10.5 Open the test valve. Record the full-open hydraulic control pressure. 

B.10.6 Repeat B.10.2 to B.10.4 until the three fresh-water closure rates have been completed or the test 

valve fails. 



35 



ISO 10432:2004(E) 


B.11 Controlled-temperature test — SCSSV 


B.11.2 Install the test valve in the controlled-temperature test stand. Temperature measurements shall be 

taken in the area of the control line entry port of the test valve. 

B.11.3 Allow the test valve to reach a stable temperature of 38 °C ± 3 °C (100 °F ± 5 °F). 

B.11.4 Apply nitrogen gas pressure of 25 % of the rated working pressure (allowable range of 20 % to 30 % 

of rated working pressure) of the test valve. Allow the temperature at the test valve to stabilize. Record the 

test valve temperature and the test valve bore pressure (base pressure). 

B.11.5 Cycle the test valve ten times while maintaining the specified test valve temperature and pressure 

recorded in B.11.4 within the specified ranges. 






test section pressure recorded at the time of each opening/closing pressure measurement. If the ten adjusted 

hydraulic control pressures do not repeat within ± 10 % of their average, or ± 0,7 MPa (± 100 psi), whichever 

is greater, or if any body joint leakage (tubing-retrievable only) is detected, the test valve fails. 

B.11.6 Connect a tube from the test valve hydraulic control line port to a container filled with water. Position 

the tube so any gas bubbles from the hydraulic control line port can be observed. 

B.11.7 With the test valve bore filled with nitrogen gas at the specified temperature and pressure, wait a 

minimum of 3 min and then observe for gas bubble leakage continuously for a minimum of 5 min. Record the 

times at which the 3 min waiting period, preceding the leakage test, begins and ends and the times at which 

the 5 min gas bubble leakage observation period begins and ends. If continuous leakage from the control line 

is observed for at least 1 min during the observation period, or if body joint leakage (tubing-retrievable only) is 

detected, the test valve fails. 

B.11.8 Repeat B.11.3 to B.11.7 using a test valve bore pressure of 75 % of the rated working pressure 

(allowable range of 70 % to 80 % of rated working pressure) of the test valve. 

B.11.9 Bleed nitrogen pressure above the closure mechanism to zero. Adjust and stabilize the pressure 

below the closure mechanism to 75 % of the rated working pressure (allowable range of 70 % to 80 % of rated 

working pressure) of the test valve. Wait a minimum of 1 min, then measure any nitrogen leakage across the 

closure mechanism. Record the test valve bore pressure below the closure mechanism, any leakage, and the 

start and completion times of the waiting period. If the leakage rate is greater than 0,14 m 3 /min (5 scf/min), or 

if any body joint leakage (tubing-retrievable only) is detected, the test valve fails. 

B.11.10 Repeat B.11.3 to B.11.8 using a stabilized temperature of 82 °C ± 3 °C (180 °F ± 5 °F). 

B.11.11 Bleed all pressure to zero. Allow the test valve to cool. Remove the test valve from the 

controlled-temperature test stand. 

B.12 Class 2 flow test — SCSSV 


B.12.2 Prepare a slurry consisting of sand and viscosified water. 

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36 






ISO 10432:2004(E) 

B.12.3 Determine the sand content of the slurry in accordance with the API Manual of Petroleum 

Measurement Standards, Chapter 10.4. Adjust the sand content to 2 % ± 0,5 % by adding 150 µm to 180 µm 

(100 U.S. mesh to 80 U.S. mesh) sand or by diluting the slurry with fresh water. 

B.12.4 Determine the viscosity of the slurry sample with a Marsh funnel viscometer in accordance with 

ISO 10414-1. Adjust the viscosity to 70 s ± 5 s by adding a viscosifier or diluting the slurry with fresh water. 


B.12.5 The viscosity and sand content requirements specified above shall be met before proceeding. 

B.12.6 Adjust the slurry circulation rate to the value specified in Table F.2. Record the slurry circulation rate, 

sand content and slurry viscosity. Record the time at which the slurry circulation begins. 

B.12.7 Circulate the slurry through the test valve at the specified rate for a minimum of 1 h, and then close 

the test valve against the specified rate. 

B.12.8 Record the full-closed hydraulic control pressure and the slurry flow rate through the test valve at the 

time closure is initiated. The test valve shall shut off a minimum of 95 % of the specified flow at the first 

closure attempt in 15,0 s or less after the hydraulic control pressure reaches zero or the test valve fails. 

Record the time required for the test valve to shut off the specified flow. If the test valve fails, discontinue 

testing. 

B.12.9 At the completion of the flow period, measure and record the sand content of the slurry and the slurry 

viscosity. 

B.13 Validation test procedure — SSCSV 

B.13.1 Verify that the model and serial numbers appearing on the test valve assembly are in agreement with 

the manufacturer's application. 

B.13.2 Perform the SSCSV gas closure test (B.14). For velocity-type SSCSVs, use the gas flow test stand to 

conduct the test. 

B.13.3 Perform the initial liquid closure test (B.15) using water as the test medium. 

B.13.4 Perform the liquid leakage test (B.5). 

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 

closure test (B.15), using water as the test medium.” Record the results as specified in F.1.16. The closing 

flow rate for a velocity-type SSCSV or the closing pressure for a tubing-pressure-type SSCSV shall repeat 

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, 

discontinue testing. 

B.13.6 Perform the nitrogen leakage test (B.9), omitting B.9.4. Record the results as specified in F.1.17. 

B.13.7 Perform the SSCSV Class 1 flow test (B.16). 

B.13.8 Repeat B.13.6 and B.13.7 fourteen additional times. The closing flow rate for velocity-type SSCSVs or 

the closing pressure for tubing-pressure-type SSCSVs shall repeat within ± 15 % of the closing flow rate or 

pressure of B.13.3 above, or the valve fails the test. If the test valve fails, discontinue testing. 

B.13.9 Perform the liquid leakage test (see B.5). If the test valve is being qualified for Class 1 service only, 

proceed to B.13.14. 

B.13.10 Perform the nitrogen leakage test (see B.9), omitting B.9.4. 



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37 



ISO 10432:2004(E) 


B.13.11 Perform the Class 2 flow test (see B.17). Class 2 flow testing shall be performed in a continuous 

manner with no interruptions longer than 2 h. 

B.13.12 Repeat B.13.10 and B.13.11 six additional times. The closing flow rate for a velocity-type SSCSV or 

the closing pressure for a tubing-pressure-type SSCSV shall repeat within ± 15 % of the closing flow rate or 

pressure of B.13.3, or the test valve fails the test. 

B.13.13 Perform the liquid leakage test (see B.5). 

B.13.14 If the test valve has performed within the limits specified, it has passed the validation test. 

B.13.15 Summarize the validation test data as specified in F.1.13. 

B.14 Gas closure test — SSCSV 


B.14.2 Increase gas pressure in the system to between 13,8 MPa (2 000 psi) and 17,3 MPa (2 500 psi). 

B.14.3 Close the test valve as follows. 

a) Velocity-type SSCSVs — Increase the gas flow rate through the test valve until the test valve closes. The 

test valve shall close at a flow rate of at least ± 25 % of the design closing flow rate indicated in F.1.1 in 

30 s or less from the time this flow rate is achieved, or the test valve fails the test. If the test valve fails, 

discontinue testing. Record the initial pressure upstream of the test valve, the differential pressure across 

the test valve closure mechanism, and the gas flow rate through the test valve at closure. 

b) Tubing-pressure-type SSCSVs — Adjust the gas pressure downstream of the test valve to ensure the test 

valve is open. Decrease the downstream pressure until the test valve closes. The test valve shall close at 

a downstream pressure of at least 75 % of the design closing pressure indicated in F.1.1. The minimum 

allowable downstream pressure is 0,35 MPa (50 psi). The test valve shall close in 30 s or less from the 

time this minimum pressure is achieved, or the test valve fails the test. Record the initial pressure 

downstream of the test valve and the pressure downstream of the test valve at closure. If the test valve 

fails, discontinue testing. 

B.14.4 Bleed the valve bore downstream pressure to zero. Adjust the test valve bore upstream pressure to 

8,3 MPa (1 200 psi) ± 5 %. Wait a minimum of 1 min, then measure any gas leakage through the closure 

mechanism. Record the test valve bore pressure, the leakage rate and the start and completion times of the 

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 

fails, discontinue testing. 

B.14.5 Bleed all pressure to zero. 

B.15 Liquid closure test — SSCSV 


B.15.2 Circulate liquid through the system while bypassing the test valve until gas has been displaced from 

the system. 

B.15.3 Adjust the circulation rate through the test valve to obtain a flow at the rate specified in Table F.3. 

B.15.4 Close the test valve as follows. 

a) Velocity-type SSCSVs — Adjust the pressure downstream of the test valve to between 0,35 MPa and 

0,38 MPa (50 psi and 55 psi). Increase the circulation rate through the valve until the valve closes. The 

38 





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ISO 10432:2004(E) 

circulation rate shall be increased such that the pressure downstream of the test valve can be maintained 

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 

± 25 % of the design closing flow rate indicated in F.1.1 in 30 s or less from the time this flow rate is 

achieved, or the test valve fails the test. If the test valve fails, discontinue testing. Record the initial 

pressure upstream of the test valve, the differential pressure across the valve closure mechanism and the 

flow rate through the valve at closure. 

b) Tubing-pressure-type SSCSVs — Decrease the downstream pressure until the test valve closes. The test 

valve shall close at a downstream pressure of at least 75 % of the design closing pressure indicated in 

F.1.1. The minimum allowable downstream pressure shall be 0,35 MPa (50 psi). The valve shall close in 

30 s or less from the time this pressure minimum is achieved, or the valve fails the test. Record the initial 

pressure downstream of the test valve and the pressure downstream of the test valve at closure. If the 

test valve fails, discontinue testing. 

B.16 Class 1 flow test — SSCSV 


B.16.2 Circulate water through the system while bypassing the test valve until gas has been displaced from 

the system. 

B.16.3 Adjust the water circulation rate through the test valve to obtain a flow rate at the value specified in 

Table F.3. Record the time at which flow is directed through the test valve and the circulation rate. Circulate 

water through the test valve at the specified rate for a minimum of 1 h. 

B.16.4 Close the test valve using the liquid closure test procedure (B.15), using water as the test medium 

and omitting B.15.1 and B.15.2. 

B.17 Class 2 flow test — SSCSV 


B.17.2 Prepare a slurry consisting of 150 µm to 180 µm (100 U.S. mesh to 80 U.S. mesh) sand and 

viscosified water. 

B.17.3 Determine the sand content of the slurry in accordance with the API Manual of Petroleum 

Measurement Standards, Chapter 10.4. Adjust the sand content to 2 % ± 0,5 % by adding 150 µm to 180 µm 

(100 U.S. mesh to 80 U.S. mesh) sand or by diluting the slurry with water. 

B.17.4 Determine the viscosity of the slurry sample with a Marsh funnel viscometer in accordance with 

ISO 10414-1. Adjust the viscosity to 70 s ± 5 s by adding a viscosifier or diluting the slurry with water. 


B.17.5 The viscosity and sand content requirements specified above shall be met before proceeding. 

B.17.6 Adjust the slurry circulation rate to the value specified in Table F.3. Record the slurry circulation rate, 

sand content and slurry viscosity. Also, record the time at which the slurry circulation begins. 

B.17.7 Circulate slurry through the test valve at the specified rate for a minimum of 1 h, and then close the 

test valve using the liquid closure test procedure (see B.15), using slurry as the test medium and omitting 

B.15.1 and B.15.2. 

B.17.8 At the completion of the circulation period, measure and record the sand content and the slurry 

viscosity. 



39 

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ISO 10432:2004(E) 


Annex C 

(normative) 

Functional testing requirements 

C.1 General 

To pass the functional test, the SSSV shall successfully complete all steps of the functional-testing procedure 

within the limits specified and in the order shown. The manufacturer's test facility shall be equipped with 

instrumentation to display and record information required by the test procedure. 

Functional testing shall be discontinued if the valve fails to perform within the limits specified for any step. The 

basis for discontinuing the test, and any unusual conditions observed at or prior to the time of discontinuance, 

shall be noted on the test data form. 

Testing may be resumed from the last successfully completed step when it is determined the cause of the 

failure is the result of a failure within the test facility. 

All pressures are defined as gauge unless otherwise specified and shall be recorded on time-based 

equipment. 

Prior to any liquid pressure test, purge with test liquid to remove air. 

Gas pressure relieving (bleed-down) operations shall be performed per the manufacturer's requirements. 

During functional testing of hydraulically operated SSSVs, control line fluid metering may be used to provide a 

readable hydraulic control line pressure trace. Refer to Figure F.6 for a characteristic pressure versus time 

plot for opening and closing hydraulic control pressures with hydraulic fluid being applied at a metered rate. 

The test section shall completely enclose a wireline-retrievable SSSV. Tubing-retrievable SSSVs shall be an 

integral part of the test section. The test section shall be rated to at least the rated working pressure of the 

SSSV. 

C.2 Functional test — SCSSV 

C.2.1 Test facility 

A typical test facility is shown in Figure F.7 and includes: 

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a) test section installed vertically; 

b) test section and hydraulic control section pressure measurement devices; 

c) pressurized-gas source; 

d) hydraulic control pressure system; 

e) flow meters; 

f) pressurized-water system; 

g) time-based recorder to simultaneously record the required data; 

h) internal and external drifts. 

40 






ISO 10432:2004(E) 

C.2.2 Functional test procedure — SCSSV 

All test section pressures shall be measured with calibrated devices and recorded. The procedure shall be as 

follows. 

a) Record test data as specified in F.1.20. 

b) Record the serial number. 

c) Place the SCSSV in a fixture capable of retaining and sealing the valve in a vertical position. 

d) Open the SCSSV with zero pressure in the test section. Adjust and stabilize the hydraulic control 

pressure to the manufacturer's recommended hold-open pressure. Isolate the hydraulic control pressure 

from the source. Monitor for a minimum of 5 min. If a loss greater than 5 % of the applied pressure is 

detected after stabilization, the SCSSV fails the functional test. 

e) Close and open the SCSSV five times with zero pressure in the test section. Record the full-closed and 

full-open hydraulic control pressures. Each control pressure shall repeat within ± 5 % of the average 

pressure of the five valve cycles as well as falling within the manufacturer's specified control pressure 

tolerance. If each pressure is not within these the limits, the SCSSV fails the functional test. 

f) Fill the test section with water or another suitable liquid to displace air from the test section, and proceed 

as follows. 

1) Wireline-retrievable SCSSVs: 

Close the SCSSV. Adjust and stabilize the pressure across the entire test section to 150 % of the 

rated working pressure (allowable range of 145 % to 155 % of the rated working pressure) for 

SCSSVs up to 69 MPa (10 000 psi) rated working pressure. For SCSSVs with rating working 

pressures in excess of 69 MPa (10 000 psi), the test pressure shall be the rated working pressure 

plus a minimum of 34,5 MPa (5 000 psi). Hold the pressure for a minimum of 5 min. Reduce the 

pressure in the test section to zero. Repeat the test once. The SCSSV fails the functional test if 

leakage is detected through the hydraulic control port(s). 

2) Tubing-retrievable SCSSVs: 

Close the SCSSV. Thoroughly dry the test valve exterior. Adjust and stabilize the pressure in the 

entire test section to 150 % of the rated working pressure (allowable range of 145 % to 155 % of the 

rated working pressure) for SCSSVs up to 69 MPa (10 000 psi) rated working pressure of the SCSSV. 

For SCSSVs with rating working pressures in excess of 69 MPa (10 000 psi), the test pressure shall 

be the rated working pressure plus a minimum of 34,5 MPa (5 000 psi). Hold the pressure a minimum 

of 5 min. Reduce the pressure in the test section to zero. Repeat the test once. The SCSSV fails the 

functional test if leakage is detected on the exterior or through the hydraulic control line port(s). 

g) Open and close the SCSSV with zero pressure in the test section and record the full-open and full-closed 

hydraulic control pressures. Open the SCSSV. 

h) Apply pressure of 50 % of the SCSSV's rated working pressure (allowable range of 45 % to 55 % of rated 

working pressure) of the test valve to the entire test section. Record the test valve bore pressure (base 

pressure). 

i) Close and open test valve five times while maintaining the test section pressure recorded in C.2.2 h) 

within the specified range. 

NOTE 

The test section pressure can increase as the valve is opened, and then can decrease as the valve is 

closed due to the differential volume of the hydraulic operating piston. 

The full-open/full-closed hydraulic control pressures shall be adjusted based on the change in test 

section pressure at the time of control pressure measurement. The adjusted control pressure is 



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41 



ISO 10432:2004(E) 


determined by adding/subtracting the actual control pressure with the difference between the base 

pressure and the actual test section pressure recorded at the time of each opening/closing pressure 

measurement. If the five adjusted hydraulic control pressures do not repeat within ± 10% of their average, 

or ± 0,7 MPa (± 100 psi), whichever is greater, or if any body joint leakage (tubing-retrievable only) is 

detected, the test valve fails. 

j) Adjust and stabilize the test section pressure to 100 % of the rated working pressure (allowable range of 

95 % to 105 % of rated working pressure) of the SCSSV. Close the SCSSV. Record the full-closed 

hydraulic control pressure. Bleed the hydraulic control pressure to zero. 

k) Adjust and stabilize the test section pressure to 100 % of the rated working pressure (allowable range of 

95 % to 105 % of rated working pressure) of the SCSSV. Monitor for leakage at hydraulic control line 

ports(s) for a minimum of 5 min. If any leakage is detected, the SCSSV fails the functional test. 

l) Bleed the pressure above the SCSSV closure mechanism to zero. Adjust and stabilize the pressure below 

the closure mechanism to 100 % of the rated working pressure (allowable range of 95 % to 105 % of 

rated working pressure) of the SCSSV. Measure liquid leakage for a minimum of 5 min. If the leakage 

rate exceeds 10 cm 3 /min, the SCSSV fails the functional test. 

m) Remove the liquid from the test section. 

n) Open the SCSSV. Record the full-open hydraulic control pressure. 

o) Adjust and stabilize the pressure in the entire test section with gas to 1,4 MPa ± 0,07 MPa 

(200 psi ± 10 psi). Close the SCSSV. Record the full-closed hydraulic control pressure. Bleed the 

hydraulic control pressure to zero. 

p) Adjust and stabilize the test section pressure with gas to 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi). Monitor 

for gas leakage at the hydraulic control port(s) for a minimum of 5 min. If any leakage is detected, the 

SCSSV fails the functional test. 

q) Bleed the pressure above the SCSSV's closure mechanism to zero. Adjust and stabilize the pressure 

below the SCSSV's closure mechanism to 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) with gas. Measure the 

leakage rate for a minimum of 5 min. If the leakage rate exceeds 0,14 m 3 /min (5 scf/min), the SCSSV 

fails the functional test. 

r) Repeat o) and p) with 8,3 MPa ± 0,41 MPa (1 200 psi ± 60 psi). 

s) Bleed all pressures to zero. 

t) Open and close the SCSSV two times. Record the full-open and full-closed hydraulic control pressures. 

u) Prepare the SCSSV for drift tests. Open the SCSSV, then, proceed as follows. 

1) Drift the interior of the SCSSV assembly with the manufacturer's specified drift bar. Pass the drift bar 

completely through the test valve. 

2) Drift the exterior of wireline-retrievable SCSSVs with the manufacturer's specified drift sleeve. If the 

SCSSV fails the drift test, it fails the functional test. 

3) Record the drift's unique identifiers and the nominal drift sizes. 

v) Special features unique to a manufacturer's SCSSV shall be tested in accordance with the manufacturer's 

operating manual. Failure to meet the requirements of these tests fails the SCSSV. These tests can be 

incorporated in the existing sequence of functional tests. Such special-feature test procedures, the 

sequence and the results shall be fully described in the test report. 

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42 






ISO 10432:2004(E) 

w) If the SCSSV performs within the limits of the functional test, it passes the functional test. Attach all 

recorded data to the manufacturer's test form. Certify the test with the appropriate manufacturer's 

approval signatures and dates. 

C.3 Functional testing — SSCSV 

C.3.1 Test facility 

A typical test facility is shown in Figure F.8 and includes the following: 

a) test section installed vertically; 

b) test section pressure measurement devices; 

c) pressurized-gas source; 

d) flow meters; 

e) pressurized-water system; 

f) time-based recorder to record the required data simultaneously; 

g) drift sleeve. 

C.3.2 Functional test procedure — velocity-type SSCSVs 

Proceed as follows. 



c) Place the SSCSV in a fixture capable of retaining and sealing the valve in a vertical position. 

d) Initiate a flow against a minimum back-pressure of 0,35 MPa (50 psi). 

e) Check the operation of the recorders for the flow rate, upstream pressure and downstream pressure. 

f) Increase flow rate until the SSCSV closes. 

g) Record the flow rate and the upstream and downstream pressures at the time of valve closure. If the 

closing rate and pressure differential are not within ± 5 % of the manufacturer's specified values, the 

SSCSV fails the functional test. 

h) Adjust and stabilize the pressure upstream of the SSCSV to 100 % ± 5 % of the rated working pressure. 

i) Hold the upstream pressure for a minimum of 5 min and measure the leakage rate. If the leakage rate 

exceeds 10 cm 3 /min, the SSCSV fails the functional test. 

j) Bleed the pressure from below the SSCSV to a value 0,7 MPa (100 psi) greater than the differential 

closing pressure. 

k) Adjust the gas pressure to a value 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) greater than the differential 


l) Measure the gas leakage rate for 5 min. If the leakage rate exceeds 0,14 m 3 /min (5 scf/min), the SSCSV 




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43 



ISO 10432:2004(E) 


m) Bleed all pressures to zero. 

n) Prepare the SSCSV for a drift test. Drift the exterior of a wireline-type SSCSV with the drift sleeve. If the 

SSCSV does not pass through the drift sleeve, it fails the functional test. Record the nominal size of the 

drift sleeve and the unique identifier. 

o) If the SSCSV performs within the limits of the functional test, it has passed the functional test. Attach all 

recorded data to the manufacturer's test form. Certify the test with the appropriate manufacturer's 

approval signatures and dates. 

C.3.3 Functional test procedure — tubing-pressure-type SSCSVs 

Proceed as follows: 



c) Place the SSCSV in a fixture capable of retaining and sealing the valve in a vertical position. 

d) Adjust the flow rate in accordance with Table F.3. 

e) Reduce the downstream pressure until the SSCSV closes. 

f) Record the flow rate and downstream pressure at the time of valve closure. If the downstream pressure at 

closure is not within ± 5 % of the manufacturer's specified pressure or 0,7 MPa (100 psi), whichever is 

larger, the SSCSV fails the functional test. 

g) Bleed the downstream pressure to zero. 

h) Adjust and stabilize the pressure upstream of the SSCSV to 100 % ± 5 % of the rated working pressure of 

the SSCSV. 

i) Hold the upstream pressure for a minimum of 5 min and measure the leakage rate. If the leakage rate 

exceeds 10 cm 3 /min, the SSCSV fails the functional test. 

j) Bleed the upstream pressure from the SSCSV to a value 0,7 MPa (100 psi) greater than the closing 

pressure. 

k) Adjust the upstream pressure with gas to a value 1,4 MPa ± 0,07 MPa (200 psi ± 10 psi) greater than the 


l) Measure the gas leakage rate for 5 min. If the leakage rate exceeds 0,14 m 3 /min (5 scf/min), the SSCSV 


m) Bleed all pressures to zero. 

n) Prepare the SSCSV for a drift test. Drift the exterior of wireline-type SSCSVs with a drift sleeve. If the 

SSCSV does not pass through the drift sleeve, it fails the functional test. 

o) If the SSCSV performs within the limits of the functional test, it has passed the test. Attach all recorded 

data to the manufacturer's test form. Certify the test with the appropriate manufacturer's approval 

signatures and dates. 

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44 






ISO 10432:2004(E) 

C.4 Functional testing — Other types of SSSV 

The following shall apply: 

a) The manufacturer shall document the functional-test procedure and record test data. 

b) The apparatus and test procedure for a specific SSSV not included in previous subclauses shall be as 

specified by the manufacturer. 

c) The manufacturer shall be responsible for assuring that the test procedures are not less stringent than 

those in this International Standard. 

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45 



ISO 10432:2004(E) 


Annex D 

(informative) 

Optional requirement for closure mechanism minimal leakage 

D.1 General 

Minimal leakage rate applies only to the functional test. If a minimal leakage requirement is specifically 

requested by user/purchaser, the supplier shall adhere to D.2 and D.3. 

NOTE 

These test requirements are optional and do not mandate minimal leakage requirements for all SSSVs. 

D.2 Gas leakage test requirements 

If the leakage rate exceeds 14,2 dm 3 /min (0,5 scfm), the SSSV fails the functional test. 

D.3 Liquid leakage test requirements 

If the leakage rate exceeds 1 cm 3 /min (0,034 fl oz/min), the SSSV fails the functional test. 

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46 






ISO 10432:2004(E) 

Annex E 

(informative) 

Operating envelope 

E.1 General 

Reference ISO 13679 or API Bull 5C3, API Bull 5C5 or other nationally or internationally accepted reference 

standards. Specifically note ISO 13679 or API Bull 5C5 procedures and test requirements for combined load 

testing. 

E.2 Envelope documentation 

If specified by the user/purchaser, an operating envelope shall be supplied for tubing-retrievable subsurface 

safety valves to illustrate the combined effects of pressure, temperature, and axial loads, as various well 

completion schemes dictate that information be available to an user/purchaser during completion/production 

operations. The operating envelope may be based upon test data and/or calculated data. 

An example envelope is illustrated below. The area within the boundaries defines the operating envelope. The 

lines forming the boundary of the envelope are defined by the various failure modes of the SCSSV. 

Key 

X axial load 

Y pressure 

a 

b 

c 

d 

Burst only (+VME). 

Collapse only (−VME). 

Compression (−VME). 

Tension (+VME). 

Figure E.1 — Operating envelope example 



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47 



ISO 10432:2004(E) 


E.3 Envelope requirements 

Operating envelopes shall meet the criteria below. 

⎯ 

⎯ 

⎯ 

The boundary lines of the envelope represent the manufacturer's maximum ratings. 

More than one graph may be displayed on the envelope if a legend is included for explanation. For 

example, calculated versus tested operating envelope data. 

The product(s) covered by the envelope shall be specified on the envelope. 

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48 






ISO 10432:2004(E) 

Annex F 

(normative) 

Data requirements, figures/schematics, and tables 

F.1 Data requirements 

F.1.1 Validation test application — SSSV (reference 6.5.2) 

a) General requirements are as follows: 

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1) identification of test agency (company/facility name, location/address, pertinent department, etc.); 

2) identification of product manufacturer (company name, location/address, pertinent department, 

contact name & phone numbers, etc.); 

3) date of validation test and date of report; 

4) validation test number (provided by test facility); 

5) if retest, reference to previous test number; 

6) the test application shall include a statement verifying a successful proof test to the anticipated test 

loads of the SSSV and all hardware supplied for the test. 

b) The equipment to be tested shall be identified as follows: 

1) equipment type: SCSSV, SSCSV (surface controlled vs. subsurface controlled, etc.); 

2) model designation or other identification by manufacturer; 

3) product number with unique serial number; 

4) nominal tubing size; 

5) rated working pressure rating; 

6) test section length; 

7) for SCSSV equipment: 

i) minimum specified ID, 

ii) 

maximum hydraulic control line pressure (greater than valve bore pressure), 

iii) maximum unequalized opening pressure; 

8) for SSCSV equipment: 

i) closing parameters (fluid velocity, pressure, design closing flow rate, etc. as appropriate), 

ii) 

tubing pressure: design closing pressure. 



49 



ISO 10432:2004(E) 


c) The following procedures and special requirements shall be stated: 

1) Class 1 or 2 service designation; 

2) Non-specified equipment or procedures required for testing; 

3) All requested variation(s) to the test agency's testing procedures shall be accurately defined, as well 

as the specific point in the testing procedure where the testing variation(s) are to be implemented. 

The specific procedures of the requested variation(s) and a document that verifies that variations to 

the requirements are not less stringent than those of the referenced standard are required as a 

component of the application. 

4) If new equipment, specific details of methods and/or practices that may be required. 

d) Space shall be provided for the following information from the test agency: 

1) testing schedule (month/day/year); 

2) test location; 

3) applicant notified (month/day/year). 

F.1.2 Gas flow test — SCSSV (reference B.3) 

The following shall be recorded: 

a) validation test number; 

b) date (month/day/year); 

c) test start time; test stop time; 

d) data to be collected/recorded for each flow test shall be as follows: 

1) hydraulic opening pressure at zero bore pressure, 

2) hydraulic closing pressure at zero bore pressure, 

3) hydraulic opening pressure at 13,8 MPa to 17,2 MPa (2 000 psi to 2 500 psi) bore pressure, 

4) closure data: 

i) gas flow rate, 

ii) 

full-closed hydraulic control pressure, 

iii) time to close, 

5) nitrogen leakage data: 

i) test pressure, 

ii) 

leakage rate, 

iii) body joint leakage detected? (yes or no); 

e) test passed? (yes or no); 

f) conducted by: (printed name and signature), date: (month/day/year). 

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50 






ISO 10432:2004(E) 

F.1.3 Drift test — SCSSV (reference B.4) 



b) drift information: 

1) minimum inside diameter or maximum outside diameter of test valve (specify ID or OD), 

2) drift bar outside diameter or drift sleeve inside diameter (specify ID or OD), 

3) drift length, 

4) unique identifier of drift bar or sleeve; 

c) for each drift test, record the following: 

1) date of test (month/day/year), 

2) full-open hydraulic control pressure (five times), 

3) full-closed hydraulic control pressure (five times), 

4) drift pass? (yes or no); 

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d) conducted by: (printed name and signature), date: (month/day/year). 

F.1.4 Initial opening and closing test — SCSSV (references B.2.2.2 and B.2.2.4) 



b) test stand (or apparatus) identification; 

c) date (month/day/year); 

d) test start time; test stop time; 

e) open and close at zero valve bore pressure: 

1) full-open hydraulic control pressure (measured), 

2) full-closed hydraulic control pressure (measured); 


F.1.5 Liquid leakage test — SSSV (reference B.5) 




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: 



51 



ISO 10432:2004(E) 


1) identification of the applicable test step being performed (note class of service as well), 


3) valve bore test pressure (nominal 100 % of rated working pressure), 

4) time at which test pressure is applied, 

5) time at start of leakage test, 

6) time at end of leakage test, 

7) average leakage rate at test pressure (100 % of rated working pressure), 

8) body leakage detected (TRSV only)? (yes or no), 

9) test step passed? (yes or no); 


F.1.6 Unequalized opening test — SCSSV (reference B.6) 





d) rated working pressure of SCSSV being tested; 

e) manufacturer's maximum recommended unequalized opening pressure (from operating manual); 

f) for each unequalized opening test, record the following: 

1) test start time; test completion time, 

2) valve bore upstream test pressure (measured), 

3) equalizing test pressure (measured), 

4) full-open hydraulic control pressure (measured); 

g) Test passed? (yes or no); 

h) conducted by: (printed name and signature), date: (month/day/year). 

F.1.7 Operating pressure test — SCSSV (reference B.7) 




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 

the following: 

52 




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ISO 10432:2004(E) 

1) date (month/day/year), 

2) initial SCSSV valve bore pressure (base pressure) at 25 % of working pressure, 

3) full-open hydraulic control pressure (and actual test section pressure), 

4) full-closed hydraulic control pressure (and actual test section pressure), 

5) record repeated cycle results as specified by the requirement in B.7, 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

6) repeat above at 75 % of working pressure; 

d) calculate the following values: 

1) adjusted hydraulic control pressure — full-closed, 

2) average of adjusted hydraulic control pressure — full-closed, 

3) adjusted hydraulic control pressure — full-open, 

4) average of adjusted hydraulic control pressure — full-open; 

e) body leakage detected (TRSV only)? (yes or no); 

f) test passed? (yes or no); 

g) conducted by: (printed name and signature), date: (month/day/year). 

F.1.8 Propane test — SSSV (reference B.8) 





d) for each of the open/close cycles at zero test valve bore pressure, record the following: 

1) full-closed hydraulic control pressure, 

2) full-open hydraulic control pressure; 

e) calculate the following values for the set of cycles just completed: 

1) average adjusted hydraulic control pressure — full-closed; same plus 10 %; same minus 10 %, 

2) average adjusted hydraulic control pressure — full-open; same plus 10 %; same minus 10 %; 

f) for each of the open/close cycles at 2,8 MPa (400 psi) test valve nominal bore pressure, record the 

following: 

1) time at valve closure, 


3) time at valve opening, 

4) full-open hydraulic control pressure; 



53 



ISO 10432:2004(E) 


g) calculate the following values for the set of cycles just completed: 

1) average adjusted hydraulic control pressure — full-closed; same plus 10 %; same minus 10 %; 

2) average adjusted hydraulic control pressure — full-open; same plus 10 %; same minus 10 %. 

h) for (each) propane soak period. record the following: 

1) time at start of soak period, 

2) time at end of soak period, 

3) valve bore pressure at end of soak period; 

i) record the last full-closed hydraulic control pressure at the end of the propane test. 

j) Test passed? (yes or no); 

k) conducted by: (printed name and signature), date: (month/day/year). 

F.1.9 Nitrogen leakage test — SSSV (reference B.9) 




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 

following: 


2) SCSSV bore pressure [1,33 MPa to 1,47 MPa (190 psi to 210 psi)], 

3) time at start of waiting period, 

4) time at completion of waiting period, 

5) measured gas leakage rate, 


7) SCSSV bore pressure [20 % to 30 % of rated working pressure (RWP)], 

8) full-open hydraulic control pressure, 





13) test passed? (yes or no); 


54 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 






ISO 10432:2004(E) 

F.1.10 Class 1 flow test — SCSSV (reference B.10) 




c) for each iteration (B.2.2.11 and B.2.2.12) of the Class 1 flow test, record the following: 


2) for each circulation flow rate record the following: 

i) time at start of circulation through test valve, 

ii) 

time at valve closure, 

iii) water flow rate immediately before valve closure, 

iv) full-closed hydraulic control pressure, 

v) flow 15 s after hydraulic control pressure reaches zero, 

vi) time to close, 

vii) full-open hydraulic control pressure; 

d) test passed? (yes or no); 

e) conducted by: (printed name and signature), date (month/day/year). 

F.1.11 Controlled temperature test — SCSSV (reference B.11) 




c) SCSSV stabilized test temperature; 

d) For each iteration (B.11.4, B.11.7, and B.11.9) of the controlled temperature test, record the following: 


2) initial SCSSV valve bore pressure (base pressure) at 25 % of working pressure at 38 °C (100 °F) and 

82 °C (180 °F), 

3) full-open hydraulic control pressure (and actual test section pressure), 

4) full-closed hydraulic control pressure (and actual test section pressure), 

5) record repeated cycle results as specified by the requirements in B.11.4, 

6) repeat above at 75 % of working pressure; 



--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

55 



ISO 10432:2004(E) 


e) Calculate the following values: 

1) adjusted hydraulic control pressure — fully-closed, 

2) average of adjusted hydraulic control pressure — fully-closed, 

3) adjusted hydraulic control pressure — fully-open, 

4) average of adjusted hydraulic control pressure — fully-open; 

f) For each control line leakage test (at specified valve temperature and pressure), record the following: 



3) leak detected? (yes or no), 

4) body leakage detected (TRSV only)? (yes or no); 

g) For each closure mechanism leakage test (at specified valve temperature and pressure below the closure 

mechanism), record the following: 

1) test temperature, 

2) time at which the bore pressure above the closure mechanism is reduced to zero, 

3) valve bore pressure below the closure mechanism, 



6) leakage rate, 

h) Test passed? (yes or no); 

i) conducted by: (printed name and signature), date: (month/day/year). 

F.1.12 Class 2 flow test — SCSSV (reference B.12) 




c) For each iteration (B.2.3.3 and B.2.3.4) of the Class 2 flow test, record the following: 


2) time at start of slurry circulation through valve, 

3) flow rate at start of circulation period, 

4) sand concentration (%) at start of circulation period, 

5) slurry viscosity at start of circulation period, 

6) time at valve closure (against slurry flow), 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

56 






ISO 10432:2004(E) 

7) slurry flow rate, 


9) flow 15 s after hydraulic control pressure reaches zero, 

10) time to close, 

11) sand concentration (%)at completion of circulation period, 

12) slurry viscosity at completion of circulation period, 



F.1.13 Validation test summary — SSSV (references A.1, B.2.3.8 and B.13.15) 


a) identification of test agency (company/facility name, location/address, pertinent department, etc.); 

b) identification of product manufacturer (company name, location/address, pertinent department, contact 

name & phone numbers, etc.); 

c) date of validation test and date of report; 

d) validation test number (provided by test facility); 

e) equipment type: SCSSV, SSCSV (surface controlled vs. subsurface controlled, etc.); 

f) model designation or other identification by manufacturer; 

g) product number with unique serial number; 

h) nominal tubing size; 

i) rated working pressure; 

j) service class tested (1 or 2); 

k) service class passed (1 or 2); 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

l) if valve failed the test, step at which the failure occurred and the reason for failure; 

m) remarks (describing any non-specified equipment or procedures requested by valve manufacturer, 

unusual conditions observed during test, etc.); 

n) test approved by: (test agency approval authority), date: (month/day/year). 

F.1.14 Gas closure test — SSCSV (reference B.14) 






57 



ISO 10432:2004(E) 


c) test start time; 

d) test completion time; 

e) date (month/day/year); 

f) for velocity-type SSCSVs: 

1) initial test valve upstream pressure, 

2) closing flow rate (gas), 

3) differential closing pressure, 

4) calculate maximum closing rate, 

5) calculate minimum closing rate; 

g) for tubing-pressure-type SSCSVs: 

1) initial test valve downstream pressure, 

2) downstream closing pressure, 

3) design closing pressure, 

4) calculate maximum closing rate, 

5) calculate minimum closing rate; 

h) nitrogen leakage data: 

1) test valve bore pressure, 

2) leakage rate; 

i) test passed? (yes or no); 

j) conducted by: (printed name and signature), date: (month/day/year). 

F.1.15 Liquid closure test — SSCSV (reference B.15) 



b) test stand (or apparatus) number; 

c) test start time; 

d) test completion time; 

e) date (month/day/year); 

f) for velocity-type SSCSVs: 


2) closing flow rate (water), 

58 




--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 



ISO 10432:2004(E) 

3) differential closing pressure, 

4) design closing flow rate (liquid), 

5) maximum closing rate: 125 % × design closing rate (liquid), 

6) minimum closing rate: 75 % × design closing rate (liquid); 

g) for tubing-pressure-type SSCSVs: 


2) downstream closing pressure, 

3) maximum closing rate: 125 % × design closing rate (liquid), 

4) minimum closing rate: 75 % × design closing rate (liquid); 

h) test passed? (yes or no); 


F.1.16 Propane test — SSCSV (reference B.13.5) 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 




c) propane soak period: 

1) date, 

2) 2 h soak period: 

i) start, 

ii) 

stop; 

3) valve bore pressure at end of 2 h soak period; 

d) closure after propane soak: 

1) test start time, 

2) test completion time, 

3) date (month/day/year); 

e) for velocity-type SSCSVs: 


2) closing flow rate (water): 

i) + 15 % of the closing flow rate recorded in F.1.15 f) 2), 

ii) − 15 % of the closing flow rate recorded in F.1.15 f) 2); 

3) differential closing pressure; 



59 



ISO 10432:2004(E) 


f) for tubing-pressure-type SSCSVs: 


2) downstream closing pressure: 

i) + 15 % of the downstream closing pressure recorded in F.1.15 g) 2), 

ii) − 15 % of the downstream closing pressure recorded in F.1.15 g) 2); 

g) test passed? (yes or no); 

h) conducted by: (printed name and signature), date: (month/day/year). 

F.1.17 Nitrogen leakage — SSCSV (reference B.13.6) 




c) for each iteration of the SSCSV nitrogen leakage test (reference B.13.6 and B.13.8): 


2) valve bore test pressure [1,33 MPa to 1,47 MPa (190 psi to 210 psi)], 




6) valve bore test pressure (20 % to 30 % RWP), 






F.1.18 Class 1 flow test — SSCSV (reference B.16) 




c) for velocity-type SSCSVs: 

1) + 15 % of closing flow rate recorded in F.1.15 f) 2), 

60 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 






ISO 10432:2004(E) 

2) − 15 % of closing flow rate recorded in F.1.15 f) 2); 

d) For tubing-pressure-type SSCSVs: 

1) + 15 % of downstream closing pressure recorded in F.1.15 g) 2), 

2) − 15 % of downstream closing pressure recorded in F.1.15 g) 2); 

e) For each iteration of the SSCSV Class 1 flow test (reference B.13.7 and B.13.8), record the following: 


2) for each circulation flow rate record the following: 


ii) 

flow rate at start of circulation period, 

iii) time at valve closure; 

3) for velocity-type SSCSVs: 

i) initial downstream pressure, 

ii) 

water flow rate at closure, 

iii) differential pressure across valve at closure; 

4) for tubing-pressure-type SSCSVs: 


ii) 

downstream pressure at closure; 

5) test passed? (yes or no). 


F.1.19 Class 2 flow test — SSCSV (reference B.17) 



b) test stand (or apparatus) number; 

c) for velocity-type SSCSVs: 

1) + 15 % of closing flow rate recorded in F.1.15 f) 2), 

2) − 15 % of closing flow rate recorded inF.1.15 f) 2); 

d) for tubing-pressure-type SSCSVs: 

1) + 15 % of downstream closing pressure recorded in F.1.15 g) 2), 

2) − 15 % of downstream closing pressure recorded in F.1.15 g) 2); 



--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

61 



ISO 10432:2004(E) 


e) For each iteration of the SSCSV Class 1 flow test (reference B.13.11 and B.13.12), record the following: 


2) For each circulation flow rate record the following: 


ii) 

flow rate at start of circulation period, 

iii) sand concentration (%) at start of circulation period, 

iv) slurry viscosity at start of circulation period (Marsh seconds), 

v) time at valve closure (against slurry flow); 

3) for velocity-type SSCSVs: 


--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

ii) 

slurry flow rate at closure, 

iii) differential pressure across valve at closure; 

4) for tubing-pressure-type SSCSVs: 


ii) 

downstream pressure at closure, 

iii) sand concentration (%) at completion, 

iv) slurry viscosity at completion of circulation period; 



F.1.20 Functional test documentation — SCSSV (reference C.2) 


a) valve manufacturer; 

b) equipment name; 

c) SSSV type and size; 

d) product/material number and unique serial number; 

e) working pressure rating; 

f) hydrostatic control pressure test: 

1) start time at pressure, 

2) end time at pressure, 

62 






ISO 10432:2004(E) 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

3) beginning control pressure, 

4) ending control pressure, 

5) calculate pressure loss over minimum of 5 min, 


g) control pressure repeatability: 

1) at zero valve bore pressure, 

2) full-open hydraulic control pressure, 


4) repeat cycle five times, 

5) calculate average of five cycles; 


h) hydrostatic test (for each iteration): 

1) start time at pressure, 

2) end time at pressure, 

3) beginning section pressure, 

4) ending section pressure, 

5) leakage within 5 min? (yes or no), 


i) record full-open/full-closed pressures; 

j) SCSSV operating pressure test: 

1) for each iteration of the operating pressure test, record the following: 

i) initial SCSSV valve bore pressure (base pressure) at 50 % of working pressure, 

ii) 

full open hydraulic control pressure (and actual test section pressure), 

iii) full-closed hydraulic control pressure (and actual test section pressure), 

iv) record repeated cycle results as specified by the requirements of C.2.2 h); 

2) calculate the following values: 

i) adjusted hydraulic control pressure — fully-closed, 

ii) 

average of adjusted hydraulic control pressure — fully-closed, 

iii) adjusted hydraulic control pressure — fully-open, 

iv) average of adjusted hydraulic control pressure — fully-open; 



63 



ISO 10432:2004(E) 


3) body joint leakage detected (TRSV only)? (yes or no); 

k) record full-open/full-closed hydraulic control pressure at 100 % test section pressure; 

l) with 100 % test section pressure and zero hydraulic control pressure: 

1) control port leakage within 5 min? (yes or no), 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 


m) closure mechanism leakage test at 100 % pressure below closure mechanism: 

1) measured leakage in cm 3 /minute within 5 min? (yes or no), 


n) record full-open hydraulic control pressure; 

o) with 1,4 MPa (200 psi) gas pressure in test section: 

1) record full-closed hydraulic pressure, 

2) control port leakage within 5 min? (yes or no), 


p) with zero test section pressure and 1,4 MPa (200 psi) gas pressure below closure mechanism: 

1) measured leakage in m 3 /min within 5 min? (yes or no), 


q) results of repeat of o) and p) at 8,3 MPa (1 200 psi); 

r) record full-open/full-closed hydraulic control pressures two times; 

s) internal/external drift test. test passed? (yes or no); 

t) special features test results. test passed? (yes or no); 

u) test date; 

v) performed by: (printed name and signature), date: (month/day/year). 

F.1.21 Functional test documentation — SSCSV (reference C.3) 


a) valve manufacturer; 

b) equipment name; 

c) SSSV type and size; 

d) SSSV catalogue/material number and unique serial number; 

e) safety valve lock, serial number, and size (as applicable); 

64 






ISO 10432:2004(E) 

f) working pressure rating; 

g) for velocity-type SSCSVs: 

1) initial flow rate, 

2) initial upstream pressure, 

3) initial downstream pressure, 

4) flow rate at moment of SSCSV closing, 

5) upstream pressure at moment of SSCSV closing, 

6) downstream pressure at moment of SSCSV closing, 

7) liquid leakage rate over period of 5 min with upstream liquid pressure equal to 100 % SSCSV rated 


8) gas leakage rate over period of 5 min with upstream gas pressure equal to 1,4 MPa (200 psi), 

9) drift test results (reference B.4), 


h) for tubing-pressure-type SSCSVs: 

1) liquid flow rate as specified in Table F.3, 

2) flow rate at moment of SSCSV closing, 

3) downstream pressure at moment of SSCSV closing, 

4) liquid leakage rate over period of 5 min with upstream liquid pressure equal to 100 % SSCSV rated 


5) gas leakage rate over period of 5 min with upstream gas pressure equal to 1,4 MPa (200 psi), 

6) drift test results (reference B.4), 



F.1.22 Shipping report — SSSV (reference 7.9.2.1) 


a) manufacturer's data: 

1) manufacturer's name and manufacturing address, 

2) product/material number, 

3) equipment name, 

4) serial number, 



65 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 



ISO 10432:2004(E) 


5) size, 

6) class of service; 

b) SSSV data: 

1) pressure rating, 

2) temperature rating, maximum, 

3) temperature rating, minimum, 

4) validation test agency, 

5) validation test number, 

6) date of report (month/day/year), 

7) tested to International Standard ISO 10432:2004; 

c) SSSV function test summary: 

1) opening pressure with zero pressure in test section: maximum and minimum, 

2) closing pressure with zero pressure in test section: maximum and minimum, 

3) performed by: (printed name and signature), date: (month/day/year); 

d) inspected by: (printed name and signature), date: (month/day/year). 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 66 






ISO 10432:2004(E) 

F.2 Figures/schematics 

Key 

1 gas supply 7 bleed valve 

2 pressure measurement device 8 leakage flow meter 

3 gas reservoir 9 flow control valve 

4 shut-off valve 10 vent 

5 flow meter 11 SSSV test section 

6 equalizing line 12 hydraulic pressure source (for SCSSVs only) 

Figure F.1 — Example schematic of gas flow facility 



--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

67 



ISO 10432:2004(E) 


--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

Key 

1 hydraulic oil 11 see Figure F.3 

2 air supply 12 by-pass valve 

3 hydraulic pressure source 13 flow meter 

4 hydraulic control system 14 recorder 

5 high-pressure water system 15 relief valve 

6 nitrogen supply 16 pump 

7 propane supply 17 drain valve 

8 manifold valves 18 water supply 

9 choke valve 19 liquid supply tank 

10 test section 

Figure F.2 — Example schematic of liquid test facility 

68 






ISO 10432:2004(E) 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

Key 

1 gas/liquid separator 10 upstream isolation valve 

2 drain 11 SSSV 

3 nitrogen flow meter 12 downstream isolation valve 

4 shut-off valve 13 balance valve 

5 test section 14 differential pressure measuring device 

6 hydraulic control line bleed valve 15 pressure-measuring device 

7 metering valve 16 high-pressure water manifold valve 

8 hydraulic control valve 17 propane manifold valve 

9 bleed valve 18 nitrogen manifold valve 

Figure F.3 — Example detail of liquid test facility 



69 



ISO 10432:2004(E) 


--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

Key 

1 hydraulic oil 8 pressure-measuring device 

2 air supply 9 test section 

3 hydraulic pressure source (for SCSSVs only) 10 thermocouple 

4 shut-off valve 11 heating chamber 

5 vent valve 12 nitrogen pressure intensifier 

6 nitrogen flow meter 13 nitrogen pressure source 

7 recorder 14 relief valve 

Figure F.4 — Example schematic of controlled-temperature test facility 

70 






ISO 10432:2004(E) 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

Key 

1 high-pressure propane tank 6 liquid shut-off valve 

2 nitrogen tank 7 low-pressure propane storage tank 

3 shut-off valve 8 SSSV 

4 relief valve 9 test section 

5 vent valve 10 pressure-measuring device 

Figure F.5 — Example schematic of propane test facility 



71 



ISO 10432:2004(E) 


Key 

X hydraulic pressure, increasing to the right 

Y time, with hydraulic control pressure applied or released at a metered rate, increasing upwards 

1 SCSSV becomes fully open 

2 hydraulic system pressure 

3 SCSSV becomes fully closed 

Figure F.6 — Example of characteristic hydraulic control pressure curve for SCSSVs 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

72 






ISO 10432:2004(E) 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

Key 

1 hydraulic oil 9 bleed valve 

2 air supply 10 equalizing line 

3 hydraulic control system 11 SSSV 

4 pressure-measuring device 12 test section 

5 recorder 13 balance valve 

6 hydraulic control valve 14 test liquid source 

7 hydraulic control line bleed valve 15 test gas source 

8 nitrogen flow meter 

Figure F.7 — Example schematic of functional-test facility for hydraulically actuated SSSVs 



73 



ISO 10432:2004(E) 


--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

Key 

1 water or high-pressure gas source 

2 flow control valve 

3 test gas source 

4 air supply 

5 test liquid source 

6 pressure-measuring device 

7 recorder 

8 nitrogen flow meter 

9 

10 

11 

12 

13 

14 

15 

16 

downstream pressure-measuring 

device 

strip-chart recorder 

flow meter 

downstream isolation valve 

bleed valve 

equalizing line 

SSSV 

test section 

17 

18 

19 

20 

21 

22 

balance valve 

connector 

upstream pressure-measuring 

device 

upstream isolation valve 

downstream pressure regulator 

water or gas return 

Figure F.8 — Example schematic of functional-test facility for velocity- and tubing-pressure-activated 

SSSVs 

74 






ISO 10432:2004(E) 

F.3 Tables 

Table F.1 — SCSSV gas flow rates (see B.3) a 

Nominal 

tubing or 

casing size 

mm (in) 

Test No. 1 

Flow rate 

m 3 /d × 10 6 (scf/d × 10 6 ) 

Gas flow rate and control line resistances for each valve closure test 

Low resistance 

Test No. 2 

Flow rate 

m 3 /d × 10 6 (scf/d × 10 6 ) 

Test No. 3 

Flow rate 

m 3 /d × 10 6 (scf/d × 10 6 ) 

High resistance 

Test No. 4 

Flow rate 

m 3 /d × 10 6 (scf/d × 10 6 ) 

60,3 (2 3/8) 0,14 (5,1) 0,22 (7,7) 0,07 (2,6) 0,14 (5,1) 

73,0 (2 7/8) 0,23 (8,0) 0,34 (12,0) 0,11 (4,0) 0,23 (8,0) 

88,9 (3 1/2) 0,33 (11,5) 0,49 (17,3) 0,16 (5,8) 0,33 (11,5) 

101,6 (4) 0,44 (15,7) 0,67 (23,6) 0,22 (7,9) 0,44 (15,7) 

114,3 (4 1/2) 0,58 (20,5) 0,87 (30,8) 0,29 (10,3) 0,58 (20,5) 

127,0 (5) 0,73 (25,9) 1,10 (38,9) 0,37 (13,0) 0,73 (25,9) 

139,7 (5 1/2) 0,91 (32,0) 1,36 (48,0) 0,45 (16,0) 0,91 (32,0) 

165,1 (6 1/2) 1,30 (46,1) 1,96 (69,2) 0,65 (23,1) 1,30 (46,1) 

177,8 (7) 1,79 (63,1) 2,68 (94,7) 0,89 (31,6) 1,79 (63,1) 

a 

See B.3.1 and B.3.2 for information on the basis of this table, and requirements for its application. 

Nominal 

tubing or 

casing size 

Table F.2 — SCSSV liquid flow rates (see B.10 and B.12) 

Circulation rate 

m 3 /d (B/D) 

(± 10 %) 

Class 1 Class 2 

mm (in) Test rate No. 1 Test rate No. 2 Test rate No. 3 

60,3 (2 3/8) 

79 (500) 

159 (1 000) 

238 (1 500) 

79 (500) 

73,0 (2 7/8) 

124 (780) 

248 (1 560) 

372 (2 340) 

124 (780) 

88,9 (3 1/2) 

178 (1 120) 

356 (2 240) 

534 (3 360) 

178 (1 120) 

101,6 (4) 

238 (1 500) 

477 (3 000) 

715 (4 500) 

238 (1 500) 

114,3 (4 1/2) 

305 (1 920) 

610 (3 840) 

915 (5 760) 

305 (1 920) 

127,0 (5) 

386 (2 430) 

772 (4 860) 

1 159 (7 290) 

386 (2 430) 

139,7 (5 1/2) 

477 (3 000) 

954 (6 000) 

1 431 (9 000) 

477 (3 000) 

165,1 (6 1/2) 

686 (4 320) 

1 373 (8 640) 

2 060 (12 960) 

686 (4 320) 

177,8 (7) 

935 (5 880) 

1 869 (11 760) 

2 804 (17 640) 

935 (5 880) 

The manufacturer establishing sizes not covered by this table may interpolate or extrapolate, 

assuming the circulation rate depends on the square of the nominal size. 



75 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 



ISO 10432:2004(E) 


Table F.3 — SSCSV liquid flow rates (see B.15, B.16 and B.17) 

Nominal tubing or casing size 

Circulation rate 

m 3 /d (B/d) 

(± 10 %) 

mm (in) Class 1 and Class 2 

60,3 (2 3/8) 

73,0 (2 7/8) 

88,9 (3 1/2) 

101,6 (4) 

114,3 (4 1/2) 

127,0 (5) 

139,7 (5 1/2) 

165,1 (6 1/2) 

177,8 (7) 

79 (500) 

124 (780) 

178 (1 120) 

238 (1 500) 

305 (1 920) 

386 (2 430) 

477 (3 000) 

687 (4 320) 

935 (5 880) 

The manufacturer establishing sizes not covered by this specification may 

interpolate or extrapolate, assuming the circulation rate depends on the square of 

the nominal size. 

--`,`````,,,,,,,,````````,,`,,,-`-`,,`,,`,`,,`--- 

76 






Annex G 

(informative) 

API Monogram 

G.0 Introduction 

The API Monogram Program allows an API Licensee to apply the API Monogram to products. Products 

stamped with the API Monogram provide observable evidence and a representation by the Licensee that, 

on the date indicated, they were produced in accordance with a verified quality management system and 

in accordance with an API product specification. The API Monogram Program delivers significant value 

to the international oil and gas industry by linking the verification of an organization's quality management 

system with the demonstrated ability to meet specific product specification requirements. 

When used in conjunction with the requirements of the API License Agreement, API Specification Q1, 

including Annex A, defines the requirements for those organizations who wish to voluntarily obtain an API 

License to provide API monogrammed products in accordance with an API product specification. 

API Monogram Program Licenses are issued only after an on-site audit has verified that the Licensee 

conforms to both the requirements described in API Specification Q1 in total, and the requirements of an 

API product specification. 

For information on becoming an API Monogram Licensee, please contact API, Quality Programs, 1220 L 

Street, N. W., Washington, DC 20005 or call 202-682-8000 or by email at quality@api.org. 

G.1 API Monogram Marking Requirements 

These marking requirements apply only to those API licensees wishing to mark their products with the 

API Monogram. 

There are no specific marking requirements for the API Monogram on API 14A SSSV equipment. 

Application of the API Monogram shall be per the manufacturers procedures as specified in API 

Specification Q1, which requires marking of the license number and date of original manufacture. 

G.2 Test Agency License Criteria 

G.2.1 The Test Agency performing validation testing must meet the requirements of Clause 6.5.3 and 

Annex A of this International Standard. In addition, for compliance with these API Monogram Program 

requirements, the Test Agency must be an Independent Third Party, and must be licensed by API in order 

to test SSSVs which are intended to be marked with the API Monogram. 

G.2.2 Laboratories desiring license under this Annex shall have a functional quality program in 

accordance with the ISO/IEC 17025 (formerly ISO/IEC Guide 25), “General Requirements for the 

Competence of Testing and Calibration Laboratories," and the requirements of API Spec Q1, except 

requirements related to product design, production, field nonconformance and nonconforming product 

release under concession. API shall maintain a list of licensed laboratories, which shall appear in the API 

Composite List of Manufacturers Licensed for use of the API Monogram. Laboratories desiring licensing 

under this Annex shall make application and pay fees as follows: 

Initial License Fee. The applicant will be assessed an initial license fee for the first Specification included 

in the application, and a separate fee for each additional Specification included in the application. 

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77 




Annual License Fee. In addition to the initial license fee, laboratories will be assessed an annual renewal 

fee for each specification under which they are listed. 

G.2.3 The Laboratory shall submit a controlled copy of their Quality Manual to API. The manual will be 

reviewed by API Staff for conformance to the requirements of Section G.2.2 of this Annex and specific 

test methods identified in this or other API Specifications. Upon acceptance of the manual, API shall 

arrange an audit, as follows: 

Initial and Renewal Audits. First-time applicants and current licensed laboratories on every third year 

renewal of licensing shall be audited by qualified auditors. The parameters of these audits shall be the 

appropriate API Specifications and the laboratory’s API accepted quality manual. The audits will be 

performed to gather objective evidence for API’s use in verifying that the laboratory is in conformance 

with the provision of the Laboratory Quality Program as applicable to this API specification and the 

requirements of G.2.2 of this Annex. The laboratory will be invoiced for the cost of these audits. 

Periodic Audits. Existing laboratories will be periodically audited by an approved API auditor on a 

nondiscriminatory basis to determine whether or not they continue to qualify as a licensed laboratory. The 

frequency of the periodic audits will be at the discretion of the staff of the Institute. The costs of periodic 

audits will be paid by the Institute. 

G.2.4 Removal of Laboratory from Composite List shall occur due to the following: 

a. Failure to meet the requirements of the audit 

b. Failure to pay annual renewal fee 

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G.2.5 Reinstatement of License Rights 

Laboratories who have been suspended may request reinstatement at any time. If a request for 

reinstatement is made within sixty (60) days after suspension, and if the reason for suspension has been 

corrected, no new application is necessary. A re-audit of the laboratory’s facilities will be made by an 

approved Institute auditor prior to a decision to reinstate license rights. The laboratory will be invoiced for 

this re-audit regardless of the Institute’s decision on reinstatement. If the result of the re-audit indicates to 

the API staff that the laboratory is qualified, the Composite List will be updated. 

If request for reinstatement is made more than sixty (60) days after suspension, the license shall be 

cancelled, and the request shall be treated as a new application unless circumstances dictate and 

extension of this time period as agreed upon by the API staff. 

G.2.6 Appeals 

A licensed organization may appeal to API any decision to suspend or cancel the license. Appeals are 

subject to the appeals procedures of API and as detailed in the contract between API and the licensed 

organization. 

G.2.7 Any changes to a Licensed Laboratory’s Quality Assurance Manual must be accepted by API in 

writing prior to implementation. 




78 




ISO 10432:2004(E) 

Bibliography 

[1] ISO/IEC Guide 22:1996, General criteria for supplier's declaration of conformity 

[2] ISO/TS 29001:2003, Petroleum, petrochemical and natural gas industries — Sector-specific quality 

management systems — Requirements for product and service supply organizations 

[3] ISO 13679, Petroleum and natural gas industries — Procedures for testing casing and tubing 

connections 

[4] API Bull 5C3, Formulas and calculations for casing, tubing, drill pipe, and line pipe properties 

[5] API Bull 5C5, Recommended practice on procedures for testing casing and tubing connections 

[6] API RP 13B1, Standard procedure for field testing water-based drilling fluids 

[7] ASNT SNT-TC-1A, Personnel qualification and certification in nondestructive testing 7) 

[8] ASTM D638, Standard test method for tensile properties of plastics 

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[9] ASTM D 1415, Standard Test Methods for Rubber Property — International Hardness 

[10] NACE MR0175/ISO 15156-1-2-3, Petroleum and natural gas industries — Materials for use in 

H 2 S-containing environments in oil and gas production 8) 

[11] SAE AS 568B, Aerospace size standard for O-rings 

[12] MIL STD 413, Visual inspection guide for elastomeric O-rings 

7) The American Society for Nondestructive Testing, 1711 Arlingate Lane, Columbus, OH 43228-0518, USA. 

8) NACE International, 1440 South Creek Drive, Houston, TX 77084-4906, USA. 



79 



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Additional copies are available through Global Engineering 

Documents at (800) 854-7179 or (303) 397-7956 

Information about API Publications, Programs and Services is 

available on the World Wide Web at http://www.api.org 

Product No: GX14A11 






PART 3: 

• Form 175-454400 


INSPECTION & TESTING REQUIREMENTS 

SAUDI ARAMCO FORM-175 

REVISION: 03/31/2013 

REPLACES: 06/15/2011 

CODE NUMBER: 

IR454400 

PAGE: 

1 of 2 

SCOPE: VALVE ASSEMBLY : Safety , Subsurface. 

TEST AND INSPECTION PER: API-14A, Purchase Order, and Specifications As Noted Below. 

0010 

(1) VISUAL INSPECTION WITNESSING BY INSPECTOR (Note 1) 

(2) CERTIFICATES / RECORDS TO BE CHECKED BY INSPECTOR 

(3) CERTIFICATES / DATA TO BE PROVIDED BY VENDOR / SUPPLIER / MANUFACTURER 

* * * 

Pre-Fabrication/Production Requirements Specification Details / Notes: 

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 

B, Annex F) 

0020 X X Pre inspection Meeting Verify Company approval of Manufacturer Inspection and test 

Plan 

0030 X Written Material Specifications (Metals & Non-Metals) Per API 14A (Clause 6.3.4). 

0040 X Written Heat Treating Equipment Qualification Procedures Per API 14A (Clause 7.3) 

0050 X Written Coating and Overlay Procedures Per API 14A (Clause 7.5) 

0060 X Welding Procedure Specifications and Procedure Qualification 

Records 

Per ASME Section IX. Company approval required. 

0070 X Welders Qualification Records Per ASME Section IX. 

0080 X NDT Procedures Per API 14A (Clause 7.6.7). Company approval required; 

Verify valid approval of procedures 

0090 X Written Dimensional and Surface Inspection Procedures Per API 14A (Clause 7.6.1 - 7.6.4) 

0100 X Written Storage and Preparation for Transport Procedures Per API 14A (Clause 9). Company approval required. 

0110 X Raw Materials and Material Test Reports Per API 14A ( Clause 7.2-7.4 and 7.6.9); MTRs to be EN 

10204 Type 3.1 

0020 

* * * 

In process inspection & test requirement Specification Details / Notes: 

0010 X NDT Personnel qualification Per API 14A (Clause 7.6.8). Verify valid qualification of 

personnel 

0020 X X Nondestructive Testing: MT, PT, UT and RT Per API 14A (Clause 7.6.7). 

0030 X Heat Treatment Per API 671 

IR454400 Continued...

INSPECTION & TESTING REQUIREMENTS 

SAUDI ARAMCO FORM-175 

REVISION: 03/31/2013 

REPLACES: 06/15/2011 

CODE NUMBER: 

IR454400 

PAGE: 

2 of 2 

(1) VISUAL INSPECTION WITNESSING BY INSPECTOR (Note 1) 

(2) CERTIFICATES / RECORDS TO BE CHECKED BY INSPECTOR 

(3) CERTIFICATES / DATA TO BE PROVIDED BY VENDOR / SUPPLIER / MANUFACTURER 

0040 X Calibration of Measuring and Testing Equipment Per API 14A (Clause 7.6.6) 

0050 X Hardness Test Per ASTM A370 and NACE-MR-01-75 for pressure retaining 

components in sour service 

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 

Specifications. All Traceable Components. 

0030 

* * * 

Final inspection & test requirements Specification Details / Notes: 

0010 X X Functional Test Per API 14A (Clause 6.7, 7.7, and Annex C); Per API 14A 

(Annex D), where specified in the purchase order. 

0020 X X Visual and Dimensional Inspection (assembly) Per API 14A (7.4 and Annex B.4) and P.O Specifications. 

0030 X Marking API 14A (Clause 7.8). Company purchase order and material 

number to be applied. 

0040 X X Documentation and Traceability Per API 14A (Clause 7.2-7.4, and 7.6.9; Annex F); MTRs to be 

EN 10204 Type 3.1. 

0040 

* * * 

Additional/Supplemental Requirements Specification Details / Notes: 

0010 X Thread Inspection and Seal Areas Per API 14A (Clause 7.6.5); For premium threads (i.e. non API 

5B threads) and for premium grades (i.e. non API). 

0020 X Thread Gauging of Thread End Per API 14A (Clause 7.6.5); Only for threads to API 5B. 

0030 X Supplied Documentation (Operating Manual) Per API 14A (Clause 7.9). 

0040 X Preparation for Shipment Per API 14A (Clause 9) and PO requirements. 

Notes: 

(1) May only be waived by the responsible Saudi Aramco, ASC, AOC Inspection Offices 

(2) See form SA175 - 000003 for instructions on using this form. 

(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. 

(4) Exposed threaded connections shall have thread preservative applied and a closed end thread protector installed; external sealing elements 

shall be protected with materials that will prevent UV and impact damage. 

End of IR454400


Charlie Chong/ Fion Fion Zhang Zhang

Knowing Subsurface Safety Valve- API14A

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