Well Integrity Technical Section

This message has been cross posted to the following Discussions: Production and Well Integrity .
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I am working on a subsea water injection well with tubing to annulus communication.  The tree valves have been successfully barrier tested, as well as the scsssv (the leak has been confirmed to be below the scsssv). The well is capable of building reservoir pressure to achieve a 3,500 kPa shut-in tubing pressure which falls off to below hydrostatic in 1 - 2 days.  This is a critical injector in the field, and is on the rig schedule to be repaired within 12 months but I am interested in opinions on continuing to inject into a well with the characteristics I have mentioned with only one barrier on the annulus side.

Thanks in advance for your time.

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Rod Gibbons

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Rod,

Unsurprisingly this comes down to a risk assessment of your particular circumstances. Clearly you have in your favour that the well is a water injector, is subsea and is sub-hydrostatic so apparently not capable of sustained flow. On the other side of the risk picture, as you point out, is the single barrier isolation on the annulus side, though most companies would consider this acceptable if the well cannot flow unassisted (this is an area to think more about as there are industry examples of water injection wells that have back flowed hydrocarbons unexpectedly).

It is quite common to allow a 2 year period to repair a tubing leak in a water injection well. This is based on anticipated production casing wall loss due to corrosion and a desire not to escalate the failure with an annulus to annulus leak. However there are many assumptions built into this 2 year period including the initial condition of the casing, the nature of completion leaks, water injection rates and water quality.

So in summary, using a rule of thumb and based on the information you provide, what you are proposing seems reasonable. However, as a critical well and to ensure you are on top of the risks I suggest you review the likelihood and nature of back flow from the well and look at the likely degradation of the production casing while injecting with a completion leak.

Regards,
Stuart Girling
stuart.girling@girlingco.com

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Stuart Girling
Director
Girling & Company
London
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Thanks Stuart, you raise some good points - this well is completed in the oil leg but has injected over 170 MMbbls of water so there is always a question of what the flowback fluid could be.  Following from your thoughts, I plan to calculate the most likely and worst case absolute open flow scenarios for use in a risk assessment.  I'll also go through the historical well data to try and estimate a potential casing metal loss and and go forward corrosion impact.

Thanks for your thoughts,  

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Rod Gibbons

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Original Message:
Sent: Sep 10,2013 04:42 AM
From: Stuart Girling
Subject: Well barrier envelope failure on water injection well

Rod,

Unsurprisingly this comes down to a risk assessment of your particular circumstances. Clearly you have in your favour that the well is a water injector, is subsea and is sub-hydrostatic so apparently not capable of sustained flow. On the other side of the risk picture, as you point out, is the single barrier isolation on the annulus side, though most companies would consider this acceptable if the well cannot flow unassisted (this is an area to think more about as there are industry examples of water injection wells that have back flowed hydrocarbons unexpectedly).

It is quite common to allow a 2 year period to repair a tubing leak in a water injection well. This is based on anticipated production casing wall loss due to corrosion and a desire not to escalate the failure with an annulus to annulus leak. However there are many assumptions built into this 2 year period including the initial condition of the casing, the nature of completion leaks, water injection rates and water quality.

So in summary, using a rule of thumb and based on the information you provide, what you are proposing seems reasonable. However, as a critical well and to ensure you are on top of the risks I suggest you review the likelihood and nature of back flow from the well and look at the likely degradation of the production casing while injecting with a completion leak.

Regards,
Stuart Girling
stuart.girling@girlingco.com

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Stuart Girling
Director
Girling & Company
London
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Hi,

While i agree that one may continue to inject, it still depends on the rate of communication with the annulus, the quality of injected water (level of oxygen in the water, bacteria etc) and DHP. To acertain the risk of not repairing the well on time, one should imagine the worst case scenario which is a flow back of HC from the reservoir, and liberation of gas in the well which migrates to the well top(expands during migration). So the question is, can the casing and formation(risk of fracturing formation) take the pressure at the well head?

So, ones you can determine the risk of a flow, then you can have a fair idea of the duration one can wait below the well repair.

Kind regards.
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Bonaventure Ani
Production Performance Engr
Total Upstream Nigeria
Victoria Island (E)
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Original Message:
Sent: Sep 10,2013 04:42 AM
From: Stuart Girling
Subject: Well barrier envelope failure on water injection well

Rod,

Unsurprisingly this comes down to a risk assessment of your particular circumstances. Clearly you have in your favour that the well is a water injector, is subsea and is sub-hydrostatic so apparently not capable of sustained flow. On the other side of the risk picture, as you point out, is the single barrier isolation on the annulus side, though most companies would consider this acceptable if the well cannot flow unassisted (this is an area to think more about as there are industry examples of water injection wells that have back flowed hydrocarbons unexpectedly).

It is quite common to allow a 2 year period to repair a tubing leak in a water injection well. This is based on anticipated production casing wall loss due to corrosion and a desire not to escalate the failure with an annulus to annulus leak. However there are many assumptions built into this 2 year period including the initial condition of the casing, the nature of completion leaks, water injection rates and water quality.

So in summary, using a rule of thumb and based on the information you provide, what you are proposing seems reasonable. However, as a critical well and to ensure you are on top of the risks I suggest you review the likelihood and nature of back flow from the well and look at the likely degradation of the production casing while injecting with a completion leak.

Regards,
Stuart Girling
stuart.girling@girlingco.com

-------------------------------------------
Stuart Girling
Director
Girling & Company
London
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Dears To continue the injection, a course of investigation and assessment is required. First of all, we have to calculate the MAASP in annulus A and compare to the injection pressure that shall not exceed 80% of the MAASP. If it exceeds, the injection pressure shall be reduced to less than 80% of the MAASP, if the injection condition permits this, otherwise, well should be shutin and secured and action plan to regain the integrity of the well. If the Tbg-casing head pressure is below 80% MAASP while injecting, a course of action shall be undertaken to complete the assessment: 1- sampling the A annulus fluid for analysis (hydrocarbon, H2S, CO2, ...) that should not exceed a certain values fixed by company policy. 2- calculate the leak rate and store volume, in our company we relay on API 14B for gas, oil and water, if it exceeds, the well also shall be secured and the leak source identified and repaired. 3- if the A annulus pressure is below 80% of the MAASP, H2S, CO2 below the allowable, and the leak rate is below the API 14B values, the well could continue the injection with a close monitoring of the pressures, sampling and analysis, and develop an action plan to regain the secondary barrier. With regards Hamdi TLWI/ADCO ------------------------------------------- Hamdi Daghmouni TL (Well Itegrity) ADCO Producing Co. Inc. Abu Dhabi -------------------------------------------
Original Message: Sent: Sep 11,2013 12:57 PM From: Bonaventure Ani Subject: Well barrier envelope failure on water injection well Hi, While i agree that one may continue to inject, it still depends on the rate of communication with the annulus, the quality of injected water (level of oxygen in the water, bacteria etc) and DHP. To acertain the risk of not repairing the well on time, one should imagine the worst case scenario which is a flow back of HC from the reservoir, and liberation of gas in the well which migrates to the well top(expands during migration). So the question is, can the casing and formation(risk of fracturing formation) take the pressure at the well head? So, ones you can determine the risk of a flow, then you can have a fair idea of the duration one can wait below the well repair. Kind regards. ------------------------------------------- Bonaventure Ani Production Performance Engr Total Upstream Nigeria Victoria Island (E) -------------------------------------------
Original Message: Sent: Sep 10,2013 04:42 AM From: Stuart Girling Subject: Well barrier envelope failure on water injection well Rod, Unsurprisingly this comes down to a risk assessment of your particular circumstances. Clearly you have in your favour that the well is a water injector, is subsea and is sub-hydrostatic so apparently not capable of sustained flow. On the other side of the risk picture, as you point out, is the single barrier isolation on the annulus side, though most companies would consider this acceptable if the well cannot flow unassisted (this is an area to think more about as there are industry examples of water injection wells that have back flowed hydrocarbons unexpectedly). It is quite common to allow a 2 year period to repair a tubing leak in a water injection well. This is based on anticipated production casing wall loss due to corrosion and a desire not to escalate the failure with an annulus to annulus leak. However there are many assumptions built into this 2 year period including the initial condition of the casing, the nature of completion leaks, water injection rates and water quality. So in summary, using a rule of thumb and based on the information you provide, what you are proposing seems reasonable. However, as a critical well and to ensure you are on top of the risks I suggest you review the likelihood and nature of back flow from the well and look at the likely degradation of the production casing while injecting with a completion leak. Regards, Stuart Girling stuart.girling@girlingco.com ------------------------------------------- Stuart Girling Director Girling & Company London -------------------------------------------
Original Message: Sent: Sep 09,2013 07:47 AM From: Rodney Gibbons Subject: Well barrier envelope failure on water injection well This message has been cross posted to the following Discussions: Production and Well Integrity . ------------------------------------------- I am working on a subsea water injection well with tubing to annulus communication. The tree valves have been successfully barrier tested, as well as the scsssv (the leak has been confirmed to be below the scsssv). The well is capable of building reservoir pressure to achieve a 3,500 kPa shut-in tubing pressure which falls off to below hydrostatic in 1 - 2 days. This is a critical injector in the field, and is on the rig schedule to be repaired within 12 months but I am interested in opinions on continuing to inject into a well with the characteristics I have mentioned with only one barrier on the annulus side. Thanks in advance for your time. ------------------------------------------- Rod Gibbons -------------------------------------------