Q&A No.714 - H2S Scavengers

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Statoil is planning a long term production test in a potential high H2S area and one of the options is to tie into an existing production pipe line in the area. To be able to do that we may need to reduce the H2S content in the well stream with several %, and we are looking for a simple (and cheap) method for reducing large H2S content.

Do you have any experience/recommendations on how to do this in an efficient way?

(The flow rate is estimated to 500 Sm3/d with oil with a GOR at approximately 200 Sm3/Sm3)

Any insights or experience would be most appreciated.

Best regards,

Odd Olav Steinveg
Lead Engineer Well Testing
DWS EXN PLN
Statoil ASA
 

asked May 25, 2016 in WTN by Odd Steinveg (180 points)

7 Answers

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Approximately 30 years ago in UK block 15/16 we used Formaldehyde as an H2S scavenger. H2S levels in the gas were 10,000-15,000 ppm from memory but can't recall the wt% in the oil. Also can't remember if it was cheap. Of course, we did have to get an excemption from the pipline operator to inject it. These days it might not be possible due to COSHH concerns.
answered May 25, 2016 by Peter Fowler (140 points)
Thanks Peter.
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Hi All,

First cheap option is by separating well stream (could be multi stage separation w/heater if needed) will help removing substantial H2S content to gaseous phase which could be routed from gas outlet to a flaring system depends on local regulations.

Second option is using sweetening unit with chemicals. Currently in PDO we are discussing H2S scavenger trial to sweeten ~5% H2S in high producer oil well. We can update once we have outcome (expected end of Q3).

R

Mohammed
answered May 26, 2016 by Mohammed Al Jabri (180 points)
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Attached is a reasonably interesting read on various scavenger chemistries and some of the advantages and disadvantages of each. (Available from Win Cubed)

Our preference has been to use chemicals that would form a stable and potentially irreversible reaction with the H2S, as well as ensuring both the product and by-products are also safe for personnel and also minimise any potential environmental hazards.

Based on this, we have looked to use Ferrous Gluconate based scavengers, but I believe the applications have primarily been in water based systems – i.e. safe disposal of water phase – as hydrocarbons are being flared.

The Bariod Sourscav is a scavenger that I understand to be based on the Ferrous Gluconate chemistry, but again for applications in water based systems (attached data sheet).

I do not know if Bariod has similar scavengers that would be effective in both the hydrocarbon fluid phases. I have not looked at these as we primarily burn/ flare off the hydrocarbons and associated H2S.

Hope some of this is useful, but would be interesting to get feedback on the final solution.

Robert Ingham

Global Well Testing Technical Specialist, BP

 

answered May 26, 2016 by Robert Ingham (180 points)
edited May 26, 2016 by Robert Ingham
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Rob has provided useful details on the approach BP had looked at for managing final scrubbing of potential H2S gas entrained in water that could not readily be completely liberated through mechanical means.  In this case we would have used relatively basic two stage separation to attempt to knock out gas from the aqueous phase and then use the scavenger to trap retained dissolved toxic gas.. As Rob indicated the suitability of these aqueous phase scavengers to effectively mix and neutralise H2S within a hydrocarbon phase may be debateable and whilst high levels of turbulence may allow suitable mixing it may not be that easy to guarantee consistent scrubbing.  I am aware that the sourscav system has also been used in underbalanced drilling situations where there was a level of H2S associated with the production stream. I am not certain if this was used with a water based mud or invert oil mud system but it apparently proved very effective.

Although H2S is very reactive and would be readily taken up by the scavenger the ability to ensure effective contact time could be difficult to achieve in a relatively limited processing system. Better scavenger mixing may be possible with oil soluble fluids but I am not aware of any cheap and effective systems and suspect effective options may have other .

Treating  500 Sm3 per day and associated gas to get it down to acceptable limits to always achieve pipeline specifications sounds like a very onerous task especially for long durations. I suspect this could be achieved with suitable process systems and scavengers but the additional process management requirements and the volumes of scavengers needed are unlikely to be simple logistics and operational management  challenges. (I am not certain my maths are correct but you would probably need in excess of 50 tonnes to treat 1% H2S by weight.

With  the possibility of upsets and sour  production bypass into any non sour rated systems resulting in major plant damage downstream and the operational hazards associated with manning any temporary process systems personnel and infrastructure equipment risks would need to be managed very carefully. Managing real time in stream H2S monitoring is also likely to be a very significant challenge. Given potential risks, is on site processing a sensible approach or would other disposal options offer a safer and potentially lower risk solution to the planned operations?

Given the potential risk profile the need for true full cycle cost effectiveness seems a  very important part of the challenge that Odd has ahead of him.

Best regards

Mike  Ward

Senior Advisor Welltesting (ex BP)
answered May 27, 2016 by Mike Ward (180 points)
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Odd Olav,

Currently we are looking at another system that would potentially take all the H2S out of all streams (see attached).

(AMGAS Clear - pdf document available from Win Cubed on request)

We are in the process of working this out.  Hopefully the attached will help somewhat.

We will still perform a HAZOP on this system to see if this will work for us…


Regards

Bart van den Bosch, 

PTE (Principal Technical Expert) Well Testing, Shell

answered May 27, 2016 by Bart van den Bosch (180 points)
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In terms of the corrosion and hazordous issue, there are lots of comercial chemicals products that make stables molecules with the H2S, making it "inert" and keeps it in the oil phase, so if there is a leakage the operators won´t be harmed by the H2S due to an expanding gas cloud. The products that we use in Petrobras that has been most sucessful are chemicals with triazine as the main component.

From what we´ve seen, in terms of quantity you´d need from 4 to 22 Liters / KG of H2S, and in practical terms it´s better to inject the chemicals at the well head instead of the surface so that you´ll have more time for the chemicals to mix. We´ve also seen that the lower the ppm of the H2S, the more inecfective the product is (Ex. with 4 ppm H2S we´ve seen no drop in the concentration of H2S in the gas after the injection of the chemical).

Now all that´s been said, mitigates the corrosion and hazordous aspect of the H2S, but not later problems for the oil processing as the H2S will still be present in the brute oil.

Regards,

Fabio Shinji OHARA
Engenheiro de Petróleo
Petrobras

answered May 30, 2016 by Fabio Shinji Ohara (140 points)
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Thank you for all your comments, we will bring this valuable information into the future planning of this project

 

Thank you regards,

Odd Steinveg
answered Jun 2, 2016 by Odd Steinveg (180 points)
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