Well Integrity Technical Section

I am seeking opinions on whether or not it is necessary to install an SCSSV in a sub-hydrostatic subsea well?

In other words, if the barriers are lost at the mud line the sea will flow into the well, not the well into the sea.

I know that this is a bit of an old question and that there have been limited cases where an SCSSV was no installed but I am wondering what criteria people might put around their decision process.  Hence the reason for the question being a bit open ended.

------------------------------
Alex Crabtree
HoustonTX
------------------------------

Hi Alex,

Going by the book, in this case NORSOK D-010 (p.22), you only need one barrier if:

a)  Undesirable cross flow between formation zones (I personally disagree with this condition without proper risk assessment)
b)  Normally pressured formation with no hydrocarbon and no potential to flow to surface
c)  Abnormally pressured hydrocarbon formation with no potential to flow to surface (e.g. tar formation without hydrocarbon vapour)

So in your case if the hydrocarbons cannot float on water, thereby finding their way to surface, and there is no associated gas the wellhead should be good enough. Keep in mind that "potential to flow" does include convection (i.e. lighter fluids bubbling through heavier seawater). I would still make sure that a fluid barrier, seawater flooding the well, is reliable enough: are there thief formations or high permeability zones that could drastically reduce your hydrostatic head?

In the end you may find resistance from regulators: even if you have a proper risk assessment and management system, and standards supporting your decision, the leak at Alison Canyon could lead people to develop a fetish for SCSSV, even in the few cases when the valve may not be needed.

Best regards,

Matteo

------------------------------
Matteo Loizzo
Well integrity consultant
Berlin

The concept of a SSSV is based on historic failure of offshore platforms due to storms and originates from the concept of storm chokes, the idea being that when the platform falls over the sssv or storm choke is set below cratering depth and safe guards the well.

It is only when leak criteria API 14 were defined that the original intend was affected and burn down philosophies got affected by piper Alpha, however the original concept of an SSSV is still applicable.

With regulators getting involved subsea wells were mandates to have sssv's with same leak criteria as for an offshore platform as specified in API 14 set at 15 scf or 400 cc ( oil) per minute that both will generate a flame of 1.5 meter and can be extinghuised by a person wearing proper ppe and a portable fire exthinghuiser. The MMS in GOM was questioned on this in 2004 to confirm this was correct interpretation as there rules quoted 15 CF for the TIF ( tree ISOLation valve on subsea wells, they confirmed they meant 15 scf.

Put your self in the position of a subsea well in 1000 ft of water with a 15scf leak rate at atmospheric pressure then you can imaging that the leak rate at seabed is insignificant, increasing water depth will get to point that the reservoir gradient may become lower then the pressure at seabed as indicated by Alex.

If you have a SSSV failure and you conduct a risk assessment you get to the situation that below a certain water depth 1000 ft plus the likely hood of damaging your last barrier is insignificant and you biggest risk is damage of dropping rig equipment like risers or BOP stags that can damage the well, DNV has got probability calculation tables for this.

This brings you to the point that the risk of doing nothing is lower then the risk of repairing the SSSV , now you can turn this around and argue what is significant affect of having a SSSV on a subsea well if the risk profile is lower then reasonable practical below a certain water depth say for example 3000 ft to give it a good safety margin to protect you against the odd anchor chain or sub marine collision event ( both happened in industry ) at 660 ft water depth in Mediterranean sea in 1980 ties.

The original intend of SSSV of a platform getting damaged is not applicable, also the operating philosophy of SSSV's in a subsea environment is often tied in to the cause and effect logic of the FPSO or platform tied in to , i.e. on ESD 3 ( fire alarm ) inventory is vented and subsea sssv plus tree are closed while really you only need to close the flow wing valve or tree isolation valve possibly just the subsea manifold if check valves are installed between multi subsea well wells and subsea manifold.

This change in operating philosophy has a considerable impact on system reliability and flow assurance i.e. no equalization of equipment less cycling of valves, use flow line packing when FPSO or platform is down and only close wing valve when flow line has reached its maximum pressure etc.

Coming back to original question is that I am convinced that you can based on a risk assessment you can justify to regulator not having a sssv in a subsea well with lower pressure of ambient or below a certain water depth, you could use the number of failures of sssv's in subsea and QRA's done on these as evidence.

I think it will take time for industry to change to accept sssv's are not needed in subsea wells that are below a certain water depth or flow potential as in my view they only increase the lifecycle risk profile while the intend is to reduce risk .

regards Paul

------Original Message------

I am seeking opinions on whether or not it is necessary to install an SCSSV in a sub-hydrostatic subsea well?

In other words, if the barriers are lost at the mud line the sea will flow into the well, not the well into the sea.

I know that this is a bit of an old question and that there have been limited cases where an SCSSV was no installed but I am wondering what criteria people might put around their decision process.  Hence the reason for the question being a bit open ended.

------------------------------
Alex Crabtree
HoustonTX
------------------------------

Alex,

Norsok D-010 states that two barriers or a DHSV should be used if there are hydrocarbons or pressure with potential to flow to surface or seabed. As long as you have hydrocarbons you should then use an SCSSV irrespective of having sub-hydrostatic pressure.

For argument sake; if you were sub-hydrostatic and omitted the SCSSV, when loosing your barriers at mudline, even though the water would flow into the well, there is a possibility that you would reach a balance point without continous flow into the well anylonger, then you could start to have hydrocarbons migrating to surface? The longer the open payzone, the higher the risk?

------------------------------
Tore Fjagesund
Technical Director
Wellbarrier AS
Stavanger

Pressure is subnormal on the wells mentioned. You put water into wells, losses result.

Why would I want a safety valve or a deep set plug that then serves no barrier purpose what so ever except add far more safety, time cost and more hazards and risks to my operational processes productivity/loss

Norske guidelines are great but has its gaps, e.g. not not cover this issue at all ALARP.

Peter.

------Original Message------

Alex,

Norsok D-010 states that two barriers or a DHSV should be used if there are hydrocarbons or pressure with potential to flow to surface or seabed. As long as you have hydrocarbons you should then use an SCSSV irrespective of having sub-hydrostatic pressure.

For argument sake; if you were sub-hydrostatic and omitted the SCSSV, when loosing your barriers at mudline, even though the water would flow into the well, there is a possibility that you would reach a balance point without continous flow into the well anylonger, then you could start to have hydrocarbons migrating to surface? The longer the open payzone, the higher the risk?

------------------------------
Tore Fjagesund
Technical Director
Wellbarrier AS
Stavanger
------------------------------

------Original Message------

I am seeking opinions on whether or not it is necessary to install an SCSSV in a sub-hydrostatic subsea well?

In other words, if the barriers are lost at the mud line the sea will flow into the well, not the well into the sea.

I know that this is a bit of an old question and that there have been limited cases where an SCSSV was no installed but I am wondering what criteria people might put around their decision process.  Hence the reason for the question being a bit open ended.

------------------------------
Alex Crabtree
HoustonTX
------------------------------

subsea sssv's if you need to install them make sure you test them till they virtually die , I know of two historic cases one in Mediterranean 1980 ties and one recent in Asia were a field was completed and one after the other failed valves in both cases were manufactured with very reputable company and in both cases it was lack of change management during manufacturing that caused it . i.e. a combination of material tolerances , spring material , change of suppliers that lead to the failures.

A good concept of sssv is the new generation subsea sssv's were piston is isolated from well bore effluents i.e. sleeve is moved with a magnetic coupling, that has no setting depth restrictions , also provides you with a dual barrier on the annulus side!

Mind you when you tear of a subsea wellhead at the H4 connector, i doubt if tubing integrity below ssssv stay in tact assume you may actually rip it out of the packer seal / anchor , the only case I know of is that the anchor chain dragged on sea bed by two tugs cut the entire wellhead off below H4 connector and sssv closed !



regards Paul

------Original Message------

Alex,

I am assuming this is for an injection well (unless you are looking at artificial lift).  

If this is an injection well, 30CFR250.801(g) states:

(g) Subsurface safety devices in injection wells. A surface-controlled SSSV or an injection valve capable of preventing backflow shall be installed in all injection wells. This requirement is not applicable if the District Manager concurs that the well is incapable of flowing. The lessee shall verify the no-flow condition of the well annually.

In addition, 30CFR250.801(a) states:

(a) General. All tubing installations open to hydrocarbon-bearing zones shall be equipped with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless, after application and justification, the well is determined by the District Manager to be incapable of natural flowing. These devices may consist of a surface-controlled subsurface safety valve (SSSV), a subsurface-controlled SSSV, an injection valve, a tubing plug, or a tubing/annular subsurface safety device, and any associated safety valve lock or landing nipple.

Assuming this is for US GOM, I would think getting approval from BSEE District Manager would require you to clearly prove that this well is incapable of flowing including any other upper formation or zone and that there is no risk for potential thief zones or high perm zones.  If this is a water injection well, consideration to potential subsequent charging of the reservoir should be considered, say in the case of banking water prior to production that could lead to well overcoming hydrostatic, although I recognize this is not very common from my experience. 

I hope this helps.

------------------------------
Jorge L. Garduño
Consultant
VIKING Engineering / GATE Inc.
HoustonTX

Original Message:
Sent: Jan 17,2016 05:02 AM
From: Paul Hopmans
Subject: When is an SSSV Needed?

subsea sssv's if you need to install them make sure you test them till they virtually die , I know of two historic cases one in Mediterranean 1980 ties and one recent in Asia were a field was completed and one after the other failed valves in both cases were manufactured with very reputable company and in both cases it was lack of change management during manufacturing that caused it . i.e. a combination of material tolerances , spring material , change of suppliers that lead to the failures.

A good concept of sssv is the new generation subsea sssv's were piston is isolated from well bore effluents i.e. sleeve is moved with a magnetic coupling, that has no setting depth restrictions , also provides you with a dual barrier on the annulus side!

Mind you when you tear of a subsea wellhead at the H4 connector, i doubt if tubing integrity below ssssv stay in tact assume you may actually rip it out of the packer seal / anchor , the only case I know of is that the anchor chain dragged on sea bed by two tugs cut the entire wellhead off below H4 connector and sssv closed !



regards Paul

Hi Matteo (and all),

following the key question and very interesting replies, don't you think that at some stage, the design of the SCSSSV closing mechanism should also be taken into consideration?

Thinking about a flapper design, risks of having the flapper open due to 'heavy' hydrostatic column is likely (hence allowing convection effect to take place).

In addition,in case of major event at seabed such as anchor chain or sub marine collision event, the flapper design is not protected against any potential debris falling on top of it and opening it.

Therefore, I believe that the design of the closure mechanism shall also be taken into consideration in the overall risk assessment.

Regards 

Philippe

------------------------------
Philippe Rabis
Well Integrity
Kobenhavn K

Original Message:
Sent: Jan 18,2016 10:44 AM
From: Jorge Garduno
Subject: When is an SSSV Needed?

Alex,

I am assuming this is for an injection well (unless you are looking at artificial lift).  

If this is an injection well, 30CFR250.801(g) states:

(g) Subsurface safety devices in injection wells. A surface-controlled SSSV or an injection valve capable of preventing backflow shall be installed in all injection wells. This requirement is not applicable if the District Manager concurs that the well is incapable of flowing. The lessee shall verify the no-flow condition of the well annually.

In addition, 30CFR250.801(a) states:

(a) General. All tubing installations open to hydrocarbon-bearing zones shall be equipped with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless, after application and justification, the well is determined by the District Manager to be incapable of natural flowing. These devices may consist of a surface-controlled subsurface safety valve (SSSV), a subsurface-controlled SSSV, an injection valve, a tubing plug, or a tubing/annular subsurface safety device, and any associated safety valve lock or landing nipple.

Assuming this is for US GOM, I would think getting approval from BSEE District Manager would require you to clearly prove that this well is incapable of flowing including any other upper formation or zone and that there is no risk for potential thief zones or high perm zones.  If this is a water injection well, consideration to potential subsequent charging of the reservoir should be considered, say in the case of banking water prior to production that could lead to well overcoming hydrostatic, although I recognize this is not very common from my experience. 

I hope this helps.

------------------------------
Jorge L. Garduño
Consultant
VIKING Engineering / GATE Inc.
HoustonTX

Hi Philippe,

------------------------------
Matteo Loizzo
Well integrity consultant
Berlin

Original Message:
Sent: Jan 19,2016 02:53 AM
From: Philippe Rabis
Subject: When is an SSSV Needed?

Hi Matteo (and all),

following the key question and very interesting replies, don't you think that at some stage, the design of the SCSSSV closing mechanism should also be taken into consideration?

Thinking about a flapper design, risks of having the flapper open due to 'heavy' hydrostatic column is likely (hence allowing convection effect to take place).

In addition,in case of major event at seabed such as anchor chain or sub marine collision event, the flapper design is not protected against any potential debris falling on top of it and opening it.

Therefore, I believe that the design of the closure mechanism shall also be taken into consideration in the overall risk assessment.

Regards 

Philippe

------------------------------
Philippe Rabis
Well Integrity
Kobenhavn K

Thank you everyone for your input.  My question was really more about the philosophy and underlying risk rather than what regulations are in place.

Thinking about if the sea is flowing into the well doesn't this imply that there is an "infinite" supply of kill weight fluid? So if some hydrocarbons migrate out of the well due to density differences doesn't this mean that the lost mass will be replaced with sea water and eventually the condition would be self limiting, i.e. worst case - the well swaps from being full of hydrocarbon to being full of sea water.  Now flowing the sea into a formation unchecked and/or emptying the well's hydrocarbon contents into the sea may be undesirable from an environmental perspective but does it actually make for a lower risk situation? 

As Paul points out, if the tubing is compromised below the SSSV the question is somewhat moot.  Also some SSSV's are only designed to prevent flow out of a well and not into it.  In these instances there would be a tendency for the sea to flow into the well anyhow and in this case I would have to question whether or not the SSSV serves any useful purpose (especially taking Peter's point).

May be the risk assessment should be more around the type of SSSV to be used rather than if it should be used?  That is, a device to prevent uncontrolled flow in either direction is required for sub-hydrostatic wells.  Would this also imply that the barrier system must also be assessed from the perspective of prevention of flow into the open formation as well as "an uncontrolled release"?

Just thinking out loud!

------------------------------
Alex Crabtree
Houston TX

Two philosophies that our industry benefits from is:

• "leave it as you found it" and
• "operate with two barriers".  

One example offshore in Gulf of Mexico.  The costs of cutting corners for any reason is something that is not affordable at 30 dollars / barrel.  Oil, Gas Leak Contained at Gulf of Mexico Oil Platform - Pemex

 Look at the incident in California that isn't offshore.   Explosion risk stalls plan to capture and burn gas from Porter Ranch leak

latimes.com		remove preview
Explosion risk stalls plan to capture and burn gas from Porter Ranch leak The possibility of a catastrophic explosion prompted state regulators Saturday to delay plans to capture and burn leaking natural gas that has sickened and displaced thousands of residents of Porter Ranch Mohsen Nazemi, deputy executive officer of the South Coast Air Quality Management District, whose hearing board was expected to approve the plan at a public meeting in Granada Hills, acknowledged the proposal was "very unusual" and that the idea is now on hold until local fire officials and state and federal regulators, have signed off on it. View this on latimes.com >

 Whether a well is on a vacuum / a pump / or is HTHP.   Use two barriers both internally and in annulus,  Plan the decommissioning of a well system so there are no channels between formations and the surface area is enhanced to suit the best purposes of the community and contributing to assure environmental sustainability.   

------------------------------
Wayne Needoba
D&C, Decommission Project Coordinator
LIS Thailand Co. Ltd.
KarawaraWA

Original Message:
Sent: Jan 18,2016 10:46 AM
From: Alexander Crabtree
Subject: When is an SSSV Needed?

Thank you everyone for your input.  My question was really more about the philosophy and underlying risk rather than what regulations are in place.

Thinking about if the sea is flowing into the well doesn't this imply that there is an "infinite" supply of kill weight fluid? So if some hydrocarbons migrate out of the well due to density differences doesn't this mean that the lost mass will be replaced with sea water and eventually the condition would be self limiting, i.e. worst case - the well swaps from being full of hydrocarbon to being full of sea water.  Now flowing the sea into a formation unchecked and/or emptying the well's hydrocarbon contents into the sea may be undesirable from an environmental perspective but does it actually make for a lower risk situation? 

As Paul points out, if the tubing is compromised below the SSSV the question is somewhat moot.  Also some SSSV's are only designed to prevent flow out of a well and not into it.  In these instances there would be a tendency for the sea to flow into the well anyhow and in this case I would have to question whether or not the SSSV serves any useful purpose (especially taking Peter's point).

May be the risk assessment should be more around the type of SSSV to be used rather than if it should be used?  That is, a device to prevent uncontrolled flow in either direction is required for sub-hydrostatic wells.  Would this also imply that the barrier system must also be assessed from the perspective of prevention of flow into the open formation as well as "an uncontrolled release"?

Just thinking out loud!

------------------------------
Alex Crabtree
Houston TX

Alex,

You have encouraged an interesting discussion. Here are some more thoughts.

As you point out this is a question of philosophy, not just regulation. It is really a risk assessment question. My comments are based on first principles risk assessment, rather than established standards.

You need to understand:

• What is the undesired outcome you want to avoid?
• What are the initial pressure source and pressure sink?
• Is there potential for the source/sink arrangement to change as reservoir pressure changes over time?
• Could the reservoir produce hydrocarbons if the tree/wellhead were removed or damaged? What is the probability of that?
• What flow rate could occur? (to determine the severity/consequences part of the risk equation)

As you have framed it, and considering the most obvious risk to well integrity, the risk assessment should be straightforward, i.e.

• the undesired outcome you want to avoid is a flow of hydrocarbons to the sea after mechanical damage to the well
• the sea is the pressure source (initially at least)
• the reservoir is the pressure sink (initially at least)
• if you lose tree integrity the sea flows through the well to the reservoir
• there is possibility of fishing net damage, anchor (and chain) damage and dropped object (BOP and marine riser) damage to the well. The probability of these events depends on the well location (and water depth) and local fishing and shipping activity, rig operations on and adjacent to the well and practices employed by the drilling contractor
• there is historical evidence of all of these events (some indicated by Paul). The probability of any of them occurring is very small (and as also indicated by Paul can be quantified using industry data)
• the probability of any of these occurring diminishes with increasing water depth
• the consequence of damage to the wellhead (in the context of the specified undesired outcome) is zero, because the sea flows into the well and there is no hydrocarbon flow to the sea
• therefore the risk is zero (with respect to the specified undesired outcome) so it is not necessary to have a safety valve

However I made some assumptions in the analysis above that may over simplify the real situation. The risk assessment may actually be more influenced by reservoir characteristics than mechanical integrity. You can think about these questions:

• could the pressure sink become the pressure source?
• is it possible that hydrocarbons could flow from the reservoir through the well to the sea? (and what is the probability of that?)
• can the reservoir characteristics and flow dynamics be such that hydrocarbons can percolate up the well? (even potentially at the same time as a flow of seawater down the well into the reservoir)

To answer these questions you need to think about reservoir characteristics:

• reservoir geometry and hydrocarbon to water contact depth(s) relative to the exposed reservoir in the well,
• volume of water injected into the well and its effectiveness in sweeping any hydrocarbons away from the wellbore (if the well is a water injector)
• reservoir development plan in terms of future reservoir pressure and well use (and whether higher reservoir pressure in the future could mean the reservoir is the pressure source rather than the sink)

This could be where your biggest uncertainties lie – what the reservoir model says and reality could be very different and could have a big impact on future well integrity. There are examples of water injection wells being back flowed flowing hydrocarbons, even after injecting millions of barrels of seawater.

You also hint that hydrocarbon flow from the well is not the only undesired event you are concerned about. Clearly if your well is in a body of water connected to the world’s oceans you would have a near infinite source of seawater to flow into the well. You would need to think about the volumetrics if your well were in an inland sea to avoid a different sort of environmental problem (though as pointed out already a flapper type safety valve wouldn’t help in this situation).

You can quantify the probability of your undesired outcome occurring (whatever that may be) and the consequences of it. You can thereby make a risk assessment that would help you decide:

• whether a safety valve is required,
• what type to use if one is needed,
• whether you would replace it if it failed
• whether the risk of each scenario (undesired outcome) is acceptable (if it is negligible or can be managed) , and
• how these risk(s) compare to other risks in your field and portfolio of fields.

A first principles risk assessment considering these issues (and others related to the specific circumstances of a particular well) will give you a more objective answer than a regulation or industry standard, that is necessarily based on generic scenarios.

------------------------------
Stuart Girling
London

Original Message:
Sent: Jan 18,2016 10:46 AM
From: Alexander Crabtree
Subject: When is an SSSV Needed?

Thank you everyone for your input.  My question was really more about the philosophy and underlying risk rather than what regulations are in place.

Thinking about if the sea is flowing into the well doesn't this imply that there is an "infinite" supply of kill weight fluid? So if some hydrocarbons migrate out of the well due to density differences doesn't this mean that the lost mass will be replaced with sea water and eventually the condition would be self limiting, i.e. worst case - the well swaps from being full of hydrocarbon to being full of sea water.  Now flowing the sea into a formation unchecked and/or emptying the well's hydrocarbon contents into the sea may be undesirable from an environmental perspective but does it actually make for a lower risk situation? 

As Paul points out, if the tubing is compromised below the SSSV the question is somewhat moot.  Also some SSSV's are only designed to prevent flow out of a well and not into it.  In these instances there would be a tendency for the sea to flow into the well anyhow and in this case I would have to question whether or not the SSSV serves any useful purpose (especially taking Peter's point).

May be the risk assessment should be more around the type of SSSV to be used rather than if it should be used?  That is, a device to prevent uncontrolled flow in either direction is required for sub-hydrostatic wells.  Would this also imply that the barrier system must also be assessed from the perspective of prevention of flow into the open formation as well as "an uncontrolled release"?

Just thinking out loud!

------------------------------
Alex Crabtree
Houston TX

A very interesting discussion .......

Can I extend it further by asking about the correspondents thoughts and opinions on:

• the selection  of a conventional surface ( hydraulic pressure)  controlled SSV in water injection wells

vs

• the selection of an water injection check valve ( injection pressure controlled) tested in accordance with ISO 10432 leakage rates for SSSVs ?

------------------------------
Alan Brodie
PTC Middle East Region Manager

Abu Dhabi

Original Message:
Sent: Jan 24,2016 10:17 AM
From: Stuart Girling
Subject: When is an SSSV Needed?

Alex,

You have encouraged an interesting discussion. Here are some more thoughts.

As you point out this is a question of philosophy, not just regulation. It is really a risk assessment question. My comments are based on first principles risk assessment, rather than established standards.

You need to understand:

• What is the undesired outcome you want to avoid?


• What are the initial pressure source and pressure sink?


• Is there potential for the source/sink arrangement to change as reservoir pressure changes over time?


• Could the reservoir produce hydrocarbons if the tree/wellhead were removed or damaged? What is the probability of that?


• What flow rate could occur? (to determine the severity/consequences part of the risk equation)

As you have framed it, and considering the most obvious risk to well integrity, the risk assessment should be straightforward, i.e.

• the undesired outcome you want to avoid is a flow of hydrocarbons to the sea after mechanical damage to the well


• the sea is the pressure source (initially at least)


• the reservoir is the pressure sink (initially at least)


• if you lose tree integrity the sea flows through the well to the reservoir


• there is possibility of fishing net damage, anchor (and chain) damage and dropped object (BOP and marine riser) damage to the well. The probability of these events depends on the well location (and water depth) and local fishing and shipping activity, rig operations on and adjacent to the well and practices employed by the drilling contractor


• there is historical evidence of all of these events (some indicated by Paul). The probability of any of them occurring is very small (and as also indicated by Paul can be quantified using industry data)


• the probability of any of these occurring diminishes with increasing water depth


• the consequence of damage to the wellhead (in the context of the specified undesired outcome) is zero, because the sea flows into the well and there is no hydrocarbon flow to the sea


• therefore the risk is zero (with respect to the specified undesired outcome) so it is not necessary to have a safety valve

However I made some assumptions in the analysis above that may over simplify the real situation. The risk assessment may actually be more influenced by reservoir characteristics than mechanical integrity. You can think about these questions:

• could the pressure sink become the pressure source?


• is it possible that hydrocarbons could flow from the reservoir through the well to the sea? (and what is the probability of that?)


• can the reservoir characteristics and flow dynamics be such that hydrocarbons can percolate up the well? (even potentially at the same time as a flow of seawater down the well into the reservoir)

To answer these questions you need to think about reservoir characteristics:

• reservoir geometry and hydrocarbon to water contact depth(s) relative to the exposed reservoir in the well,


• volume of water injected into the well and its effectiveness in sweeping any hydrocarbons away from the wellbore (if the well is a water injector)


• reservoir development plan in terms of future reservoir pressure and well use (and whether higher reservoir pressure in the future could mean the reservoir is the pressure source rather than the sink)

This could be where your biggest uncertainties lie – what the reservoir model says and reality could be very different and could have a big impact on future well integrity. There are examples of water injection wells being back flowed flowing hydrocarbons, even after injecting millions of barrels of seawater.

You also hint that hydrocarbon flow from the well is not the only undesired event you are concerned about. Clearly if your well is in a body of water connected to the world’s oceans you would have a near infinite source of seawater to flow into the well. You would need to think about the volumetrics if your well were in an inland sea to avoid a different sort of environmental problem (though as pointed out already a flapper type safety valve wouldn’t help in this situation).

You can quantify the probability of your undesired outcome occurring (whatever that may be) and the consequences of it. You can thereby make a risk assessment that would help you decide:

• whether a safety valve is required,


• what type to use if one is needed,


• whether you would replace it if it failed


• whether the risk of each scenario (undesired outcome) is acceptable (if it is negligible or can be managed) , and


• how these risk(s) compare to other risks in your field and portfolio of fields.

A first principles risk assessment considering these issues (and others related to the specific circumstances of a particular well) will give you a more objective answer than a regulation or industry standard, that is necessarily based on generic scenarios.

------------------------------
Stuart Girling
London

Norm in general is that a well that is connected to a hydrocarbon reservoir and has capability of flow to surface or seabed requires a subsurface safety valve in offshore environment this would include lakes, swamp as the environmental impact is in most cases unacceptable, when a subsurface safety device is deployed the API 14 rule of 15 scf or 400 cc kicks in , some operators adjust the leak acceptance criteria with taking soem credit for teh seabed ambient pressure on subsea wells.

I think the discussion is about when would you be able to justify not to install or replace a failed sssv when the well is no longer capable of sustained flow to surface / seabed.

The challenge I put on the table if the sssv is to minimize the risk of loosing integrity form a subsea well head and there is no risk of damaging or loosing containment due to water depth do yo still need sssv's in deepwater

regards Paul

------Original Message------

A very interesting discussion .......

Can I extend it further by asking about the correspondents thoughts and opinions on:

• the selection  of a conventional surface ( hydraulic pressure)  controlled SSV in water injection wells

vs

• the selection of an water injection check valve ( injection pressure controlled) tested in accordance with ISO 10432 leakage rates for SSSVs ?

------------------------------
Alan Brodie
PTC Middle East Region Manager

Abu Dhabi
------------------------------

If you have zero probability of hydrocarbon flow from the well and/or zero probability of damage to the well the risk is zero and therefore a safety valve would not be required.

But the big problem with this statement is the small word “if”.

You could convince yourself that there is no probability of fishing net, ship anchor or dropped objects damage in deep water. But can you be certain that nothing else could cause loss of containment – corrosion, manufacturing defect, or something else you hadn’t thought of when the well was completed?

There could be similar uncertainties when assessing the probability of hydrocarbon flow. Do you really understand the dynamics of your reservoir (and other potentially hydrocarbon bearing formations) so well you can be certain it would never happen?

It is these uncertainties, in the context of the relatively low cost of installing a safety valve and the potentially painful consequences of getting it wrong, that make installing a safety valve the prudent thing to do. Ultimately it comes down to how confident you (and your management) are in your risk assessment.

The more interesting challenge is what to do if the valve fails in service. Replacing or repairing it may be less safe, in terms of total risk, than leaving it in the failed state as you introduce new hazards by doing an intervention or workover. A well thought through risk assessment would be needed for this, with special consideration needed if the safety valve is designated a Safety Critical Element.

For Alan’s point on choice of surface versus injection pressure controlled safety valves I think it comes down to relative reliability between the two systems (and how confident you are in the failure probability data). In my experience the differences are not significant in terms of overall risk. A big difference I see is in perception, of both oil company engineers and regulators, who often are more familiar and comfortable with surface controlled devices.

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Stuart Girling
Girling & Company
London

Original Message:
Sent: Jan 26,2016 05:52 AM
From: Paul Hopmans
Subject: When is an SSSV Needed?

Norm in general is that a well that is connected to a hydrocarbon reservoir and has capability of flow to surface or seabed requires a subsurface safety valve in offshore environment this would include lakes, swamp as the environmental impact is in most cases unacceptable, when a subsurface safety device is deployed the API 14 rule of 15 scf or 400 cc kicks in , some operators adjust the leak acceptance criteria with taking soem credit for teh seabed ambient pressure on subsea wells.

I think the discussion is about when would you be able to justify not to install or replace a failed sssv when the well is no longer capable of sustained flow to surface / seabed.

The challenge I put on the table if the sssv is to minimize the risk of loosing integrity form a subsea well head and there is no risk of damaging or loosing containment due to water depth do yo still need sssv's in deepwater

regards Paul

Re Stuart's comment

"choice of surface versus injection pressure controlled safety valves I think it comes down to relative reliability between the two systems (and how confident you are in the failure probability data). In my experience the differences are not significant in terms of overall risk. A big difference I see is in perception, of both oil company engineers and regulators, who often are more familiar and comfortable with surface controlled devices"

As you say there is little if any technical difference in the performance of the competing systems.

However the key differentiator the injection pressure controlled WI well safety valves offer will most likely be reduced cost.

A critical advantage in todays cost cutting environment.

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Alan Brodie
PTC Middle East Region Manager

Abu Dhabi

Original Message:
Sent: Jan 27,2016 02:50 PM
From: Stuart Girling
Subject: When is an SSSV Needed?

If you have zero probability of hydrocarbon flow from the well and/or zero probability of damage to the well the risk is zero and therefore a safety valve would not be required.

But the big problem with this statement is the small word “if”.

You could convince yourself that there is no probability of fishing net, ship anchor or dropped objects damage in deep water. But can you be certain that nothing else could cause loss of containment – corrosion, manufacturing defect, or something else you hadn’t thought of when the well was completed?

There could be similar uncertainties when assessing the probability of hydrocarbon flow. Do you really understand the dynamics of your reservoir (and other potentially hydrocarbon bearing formations) so well you can be certain it would never happen?

It is these uncertainties, in the context of the relatively low cost of installing a safety valve and the potentially painful consequences of getting it wrong, that make installing a safety valve the prudent thing to do. Ultimately it comes down to how confident you (and your management) are in your risk assessment.

The more interesting challenge is what to do if the valve fails in service. Replacing or repairing it may be less safe, in terms of total risk, than leaving it in the failed state as you introduce new hazards by doing an intervention or workover. A well thought through risk assessment would be needed for this, with special consideration needed if the safety valve is designated a Safety Critical Element.

For Alan’s point on choice of surface versus injection pressure controlled safety valves I think it comes down to relative reliability between the two systems (and how confident you are in the failure probability data). In my experience the differences are not significant in terms of overall risk. A big difference I see is in perception, of both oil company engineers and regulators, who often are more familiar and comfortable with surface controlled devices.

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Stuart Girling
Girling & Company
London

Alan, yes indeed little difference but if you are applying the same subsea you need the whole control system as part of your investment and all the potential failure modes of this system , if you would rank that against risk exposure you would go for a downhole injection valve, wireline retrievable, with the current subsea entry systems I do not see an issue on reliability, there some good brands on the market.

Injection valves also are more forgiving on formation as they maintain the hydrostatic head in the well so you get less bull heading effects, formation damage when starting up injection, the only disadvantages is that injectors tend to get contaminated, often back flush is the preferred solution to clean up the reservoir section , mostly quite effective, with down injection valves this would not be possible unless you retrieve the valve. The disadvantage of injectors in general is that tubing is rarely clean and you're bound to run in to trouble doing wireline entries on these wells.

So bottom line is you need to look at from a lifecycle investment perspective do you're sums and determine your'e risk this will provide you the right answer on which one to select.

regards Paul

------Original Message------

Re Stuart's comment

"choice of surface versus injection pressure controlled safety valves I think it comes down to relative reliability between the two systems (and how confident you are in the failure probability data). In my experience the differences are not significant in terms of overall risk. A big difference I see is in perception, of both oil company engineers and regulators, who often are more familiar and comfortable with surface controlled devices"

As you say there is little if any technical difference in the performance of the competing systems.

However the key differentiator the injection pressure controlled WI well safety valves offer will most likely be reduced cost.

A critical advantage in todays cost cutting environment.

------------------------------
Alan Brodie
PTC Middle East Region Manager

Abu Dhabi
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