Well Integrity Technical Section

Hello Dear.

Well is completed with Hyper-1 chrome tubing & chrome packer set inside 7" p-100 production casing.

7" production casing will  be perforated at ~ 7500' to take production from casing above packer. Produced fluids will be gas with 3.8 % Co2 mole. Pressure at 7500' will be around 3500 psig.

Deeper sand will be perforated at 8500' below packer to take production from tubing . Deeper sand will contain ~ 4.5% co2 mole. pressure at 8500' will be ~ 4000 psig.

Could you please share the risk  associated with the above scenario for commingled production. What steps should be taken to mitigate the associated risks to avoid any integrity issue.

Regards
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Lajpat Rai
Petroleum Engineer
United Energy Pakistan Ltd
Karachi City
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Dear Mr.rai
Does your regulator allows you to produce gas from both annulus and tubing? What is your safety device to stop production from annulus in case of emergency ? Have you considered dual string ? Is it uneconomical to produce as duel well? P.k.borthakur

Sent from my iPad

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

Hello Dear.

Well is completed with Hyper-1 chrome tubing & chrome packer set inside 7" p-100 production casing.

7" production casing will  be perforated at ~ 7500' to take production from casing above packer. Produced fluids will be gas with 3.8 % Co2 mole. Pressure at 7500' will be around 3500 psig.

Deeper sand will be perforated at 8500' below packer to take production from tubing . Deeper sand will contain ~ 4.5% co2 mole. pressure at 8500' will be ~ 4000 psig.

Could you please share the risk  associated with the above scenario for commingled production. What steps should be taken to mitigate the associated risks to avoid any integrity issue.

Regards
------------------------------
Lajpat Rai
Petroleum Engineer
United Energy Pakistan Ltd
Karachi City
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Dear Lajpat,

I presume the Hyper-1 is 13Cr. If so your tubing and packer are wet-CO2 corrosion resistant. On the other hand, P100 (a high-grade carbon steel) is not. From your description, the production will be commingled at surface after you produce from the annulus. In this case the 7" casing will be subject to metal loss corrosion unless the gas is dry, with the possible complicating factor during shut-downs of hydrogen embrittlement from the gas produced by iron oxidation. Presence of H2S may make this worse.

I guess there is a high corrosion risk in your annulus, maybe including your wellhead and tree. How do you plan to shut down production from the casing in case of a major leak on surface?

Best regards,

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Matteo Loizzo
Well integrity consultant
Berlin
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Dear Lajpat, producing wet - Co2 using non corrosion resistant P100 casing is not what i would recommend. The risk is that eventually, your entire casing will loose integrity and the measure of risk can be elevated by the type of cementing program you use at the interval where the production casing is in contact with the formation. Another risk is the pressurizzation of other casing annulus as you will eventually have communication between casings.

I propose a dual string completion . This way, your primary envelope of control is guranteeed.

Regards
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Bonaventure Ani
Field Engineer OML99
Total E&P Nigeria Ltd.
Aberdeen
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Original Message:
Sent: Sep 22,2015 04:12 AM
From: Matteo Loizzo
Subject: Risk Analysis for commingled production (Tubing + Casing)

Dear Lajpat,

I presume the Hyper-1 is 13Cr. If so your tubing and packer are wet-CO2 corrosion resistant. On the other hand, P100 (a high-grade carbon steel) is not. From your description, the production will be commingled at surface after you produce from the annulus. In this case the 7" casing will be subject to metal loss corrosion unless the gas is dry, with the possible complicating factor during shut-downs of hydrogen embrittlement from the gas produced by iron oxidation. Presence of H2S may make this worse.

I guess there is a high corrosion risk in your annulus, maybe including your wellhead and tree. How do you plan to shut down production from the casing in case of a major leak on surface?

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
Berlin
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Lajpat,

I assume that you have the details of the risk analysis from the initial concept selection. Ideally, that should have been the best time to discuss the risks and mitigations and if required, a change in the completion design.

The ideal way of producing the two formations would have been either using dual string - the shorter string producing from the shallower formation and the long string from deeper formation. Assuming that it is not possible due to restriction of tubing size or flow rates (not mentioned in your query), the alternate completion method should have been commingled flow through the tubing with packers isolating the shallow zone and flow through SSD or FCV in the tubing. 

With the current scenario mentioned by you, the primary concern will be the safety barriers on the casing side. 

It seems that the well is not flowing now and based on the information available, I will suggest to have commingled flow through tubing as mentioned earlier in my response, if still possible.

Out of curiosity, can you specify where the flow is comingled, the downhole temperatures and the expected flow rates? I assume that the well is located onshore.

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Sudeep Roy
Oil & Gas Professional
Geneve
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