Well Integrity Technical Section

Dear Members,
In addition to surface safety valves, Subsurface safety valves are used in offshore wells and in some critical onshore environments to shut-off subsurface flow to the surface and to avoid a Loss of Well Control (LWC) incident. The requirement for installing these downhole safety valves (DHSVs) is also driven by regulatory requirements. What are the pros and cons of installing DHSVs in onshore CO2 storage wells (Class VI wells as defined in the U.S.) given the unique phase behavior characteristics of CO2 if it were to move uphole in a LWC scenario. Another aspect to be kept in mind is the requirement of a Post Injection Closure (PISC) monitoring period for Class VI CO2 injection wells that is not a requirement for CO2 -EOR wells (Class II wells as defined in the U.S.), prior to the Class VI wells being plugged and abandoned. 
My intention here is not to trigger a regulatory push, but rather to initiate a technical and engineering discussion.
Best regards,
Talib

------------------------------
Talibuddin Syed
------------------------------

Hi Talib,

Thanks for brining up the issue of  SCSSV in CO2 wells. There have been a lot of discussions, mostly with tails wagging their dog: since CO2 DHSV are complicated, then we shouldn't adopt them.
As usual, it's a decision based on mitigation: if an uncontrolled blow out is possible, with dire consequences on reputation and no easy way to stop it, then we should (shall) install a safety valve. Mind that other prevention and mitigation means are possible: increase safety & security of production trees, capturing escaping CO2, or even drill twin injectors so one can be quickly repurposed as a relief well.
However, if we have no mitigation, then a valve may be required.
There are reasons why we are loth to install them: shutting a valve with high Joule-Thomson cooling may be tricky (think sealing over a 100+ degC temperature range), and so would determining an acceptable leak rate à la API 14B. On the other hand, most injectors only accept bone-dry non-corrosive CO2, so reliability should not be a big issue.

As for post-closure monitoring, do you mean how can we assure long-term safety while monitoring reservoir pressure? I think we can happily use a flavor of temporary abandonment, or even reservoir abandonment, and still have a gauge cross the primary barrier across the caprock.

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
------------------------------

Hi Matteo,
Thank you for your response with meaningful insights and recommendations. I am curious to know whether there are (if any) SCSSV's installed in any CO2 onshore injectors globally - including within the CO2-EOR universe here in the U.S. (I am assuming there are SCSSVs installed offshore due to regulatory or company requirements). Also, it will be interesting to know how their performance has been (since operators have reported occasional problems with their functioning during normal operations in oil and gas wells).
This leads to a second thought that has crossed my mind - what happens if the well has only one primary barrier (assuming the long string casing and cement is one primary barrier and is compromised) and a properly engineered tubing and packer as the second primary barrier. Of course, this will require having a strong monitoring and surveillance program in place throughout the life of the well in addition to historical experience in that area.
And thanks for your comments related to post injection monitoring too.
Regards,
Talib

------------------------------
Talibuddin Syed
------------------------------

Original Message:
Sent: 02-06-2023 11:59 AM
From: Matteo Loizzo
Subject: Pros and Cons of Subsurface Safety Valves for CO2 Storage Wells

Hi Talib,

Thanks for brining up the issue of  SCSSV in CO2 wells. There have been a lot of discussions, mostly with tails wagging their dog: since CO2 DHSV are complicated, then we shouldn't adopt them.
As usual, it's a decision based on mitigation: if an uncontrolled blow out is possible, with dire consequences on reputation and no easy way to stop it, then we should (shall) install a safety valve. Mind that other prevention and mitigation means are possible: increase safety & security of production trees, capturing escaping CO2, or even drill twin injectors so one can be quickly repurposed as a relief well.
However, if we have no mitigation, then a valve may be required.
There are reasons why we are loth to install them: shutting a valve with high Joule-Thomson cooling may be tricky (think sealing over a 100+ degC temperature range), and so would determining an acceptable leak rate à la API 14B. On the other hand, most injectors only accept bone-dry non-corrosive CO2, so reliability should not be a big issue.

As for post-closure monitoring, do you mean how can we assure long-term safety while monitoring reservoir pressure? I think we can happily use a flavor of temporary abandonment, or even reservoir abandonment, and still have a gauge cross the primary barrier across the caprock.

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
------------------------------

Matteo has, like usual, covered all the key points. 

I will only add, SSSV should (shall) be installed in high risk wells near communities or population centers that would be impacted in the event of a large blowout.  This might be near a town or major highway. For conventional gas well blowouts the evacuation zone is 1 mile to 1/2 mile around the well at the start of the event for example.  CO2 being heavier than air, and potentially fatal, should consider the proximity to the public.

I am not an expert in all of the current SSSV designs for CO2 but historically SSSV have been developed and optimized for hydrocarbon service and 'relatively' low CO2 percentage.  It took years for the original SSSV to be refined to the high reliability we have now.  The SSSV internal seals and materials may not be designed for the high partial pressures in CO2 wells over a long time.  I would check with each major supplier and find out what they are doing to manage high partial pressure CO2 storage in their equipment design.

------------------------------
Dan Gibson
aka The Well Doctor
Completion & Well Integrity Advisor
Houston, Texas
------------------------------

Original Message:
Sent: 02-06-2023 11:59 AM
From: Matteo Loizzo
Subject: Pros and Cons of Subsurface Safety Valves for CO2 Storage Wells

Hi Talib,

Thanks for brining up the issue of  SCSSV in CO2 wells. There have been a lot of discussions, mostly with tails wagging their dog: since CO2 DHSV are complicated, then we shouldn't adopt them.
As usual, it's a decision based on mitigation: if an uncontrolled blow out is possible, with dire consequences on reputation and no easy way to stop it, then we should (shall) install a safety valve. Mind that other prevention and mitigation means are possible: increase safety & security of production trees, capturing escaping CO2, or even drill twin injectors so one can be quickly repurposed as a relief well.
However, if we have no mitigation, then a valve may be required.
There are reasons why we are loth to install them: shutting a valve with high Joule-Thomson cooling may be tricky (think sealing over a 100+ degC temperature range), and so would determining an acceptable leak rate à la API 14B. On the other hand, most injectors only accept bone-dry non-corrosive CO2, so reliability should not be a big issue.

As for post-closure monitoring, do you mean how can we assure long-term safety while monitoring reservoir pressure? I think we can happily use a flavor of temporary abandonment, or even reservoir abandonment, and still have a gauge cross the primary barrier across the caprock.

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
------------------------------

Hi all,

All good points.  To build on Dan's note about SCSSV operation with CO2-wetted seals (to which I agree 100%), I'd suggest an alternative to the traditional SCSSV: a passive injection valve.  In an injection well, all you need is a check valve; well operability doesn't require it to be an SCSSV.  Note that a passive valve is "surface controlled" but by the injected fluids, not a control fluid.  Semantics perhaps, but also possibly important when discussing with a regulator.

SCSSV hydraulics add complexity (and thus failure modes), cost, and control lines can also lead to sensitivity to annulus pressure.  The A annulus warms when an injection well is shut-in, and an emergency shut-in or similar loss of control of long duration can yield high annulus pressures that could risk an un-commanded SCSSV opening if there is a control line leak.  This can limit your maximum allowable shut-in pressure and impact overall well operability.

There are some excellent, modern passive injection valves out there.  I know of one operating as an SSV in a subsea water injection well in the US GoM right now (replacing a failed SCSSV, I might add), its gas-tight, and has been validated to -240 F.  All it needs is a landing nipple, making retrofit of existing wells pretty easy.  It doesn't use an orifice so despite being wireline retrievable, can handle very high rates.  You can run more than one, and you can run it as deep as you please.  

This is one valve and there are others.  Following extensive FMECA we're very close to recommending passive injection valves as the primary SSV (in place of SCSSVs) for the injection wells planned for a major subsea development, pending some additional project-specific validation that I believe would not apply to an onshore CO2 injection well.

This is a non-commercial forum so I won't share product details here, but would be happy to do so if contacted.  I have no business ties to any of these products.

I'll close by re-stating an opinion that I think many of us share: in many well types, SCSSVs and their lack of reliability often pose more risk through additional workovers than they offset by preventing release to the environment.  Despite their intent, many are an environmental liability.  More often than not, its the operating system that fails.  There's no way around this in a producing well but this is totally avoidable in an injector.  If you get the right valve I think you can offset a great deal of risk for relatively little cost and benefit from much-improved reliability.

I would run one in your CO2 injection wells.    

Great question and thread - thanks all.

Take care,

R

------------------------------
Ron Nelson
Subsea Completion Consultant
ron@deep-blue.ca
------------------------------

Original Message:
Sent: 02-10-2023 06:57 AM
From: Dan Gibson
Subject: Pros and Cons of Subsurface Safety Valves for CO2 Storage Wells

Matteo has, like usual, covered all the key points. 

I will only add, SSSV should (shall) be installed in high risk wells near communities or population centers that would be impacted in the event of a large blowout.  This might be near a town or major highway. For conventional gas well blowouts the evacuation zone is 1 mile to 1/2 mile around the well at the start of the event for example.  CO2 being heavier than air, and potentially fatal, should consider the proximity to the public.

I am not an expert in all of the current SSSV designs for CO2 but historically SSSV have been developed and optimized for hydrocarbon service and 'relatively' low CO2 percentage.  It took years for the original SSSV to be refined to the high reliability we have now.  The SSSV internal seals and materials may not be designed for the high partial pressures in CO2 wells over a long time.  I would check with each major supplier and find out what they are doing to manage high partial pressure CO2 storage in their equipment design.

------------------------------
Dan Gibson
aka The Well Doctor
Completion & Well Integrity Advisor
Houston, Texas
------------------------------


Original Message:
Sent: 02-06-2023 11:59 AM
From: Matteo Loizzo
Subject: Pros and Cons of Subsurface Safety Valves for CO2 Storage Wells

Hi Talib,

Thanks for brining up the issue of  SCSSV in CO2 wells. There have been a lot of discussions, mostly with tails wagging their dog: since CO2 DHSV are complicated, then we shouldn't adopt them.
As usual, it's a decision based on mitigation: if an uncontrolled blow out is possible, with dire consequences on reputation and no easy way to stop it, then we should (shall) install a safety valve. Mind that other prevention and mitigation means are possible: increase safety & security of production trees, capturing escaping CO2, or even drill twin injectors so one can be quickly repurposed as a relief well.
However, if we have no mitigation, then a valve may be required.
There are reasons why we are loth to install them: shutting a valve with high Joule-Thomson cooling may be tricky (think sealing over a 100+ degC temperature range), and so would determining an acceptable leak rate à la API 14B. On the other hand, most injectors only accept bone-dry non-corrosive CO2, so reliability should not be a big issue.

As for post-closure monitoring, do you mean how can we assure long-term safety while monitoring reservoir pressure? I think we can happily use a flavor of temporary abandonment, or even reservoir abandonment, and still have a gauge cross the primary barrier across the caprock.

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany