H2S Levels in Natural Gas 1

[Trond]

Hi everyone,

We have offshore oil & gas platforms with some wells producing H2S. Recently it was found that one of our wells had reached 600 PPM H2S. We do not have H2S detectors on the platforms, and the well was therefore shut down. This to me seems a bit excessive. Whereas 600 PPM H2S inhaled will lead to rapid loss of conciousness, so will inhaling of pure natural gas!

Considering that these are wells in a well ventilated area, and any major releases would be picked up by inline pressure alarms and gas detectors in the area, would it not be safe to keep the system running with a H2S concentration of even more than 600 PPM?

Eagerly awaiting your words of wisdom

Trond

 

[TD2K]

For personnel exposure during a leak, I'd agree 600 ppm H2S in the gas isn't a major problem. Continuous exposure limit is, I believe, 10 ppm and you'd have close to the LEL of natural gas to have this much H2S in the air so you'd have bigger problems at that point IMO. To get to levels where immediate health problems to H2S exposure are seen (close to 100 ppmv), you have very high levels of NG in the air. However, H2S also tends to concentrate in low areas and that may be a factor in your company's decision. There may also be government regulation requirements that kick in above certain levels of H2S they don't want to have to deal with.

There are some other possibilities. 600 ppm H2S in the gas could easily be enough to qualify the gas as sour, are the pipelines and fittings fabrictated to NACE standards?

Also, where is this gas going and what is the downstream processing? I believe H2S limits in commercial pipeline NG is about 4 ppmv which means you have to dilute this single well's output with a lot of sweet gas to meet the overall H2S spec if it isn't being further treated.

 

[AKVecoPE]

Trond

In the mid-eighties I was on the design team for the Lisburne oil field on the North Slope of Alaska. We were told by our reservoir engineers to expect "significant" H2S concentrations in the produced gas. Since most of the surface equipment is housed, H2S detection was a topic of much discussion.

We eventually came to the conclusion that we had two areas of concern - TEG regeneration and water handling.

Given that we use gas detection with an initial alarm at 25% of LEL, calibrated either on Methane (ceilings) or Propane (floor), it was determined that we only needed H2S detection where OSHA limits could be reached before the combustible gas detectors would reach alarm.

IIRC, this translated to an H2S concentration around 2,000 ppm. Since H2S concentrates in TEG and in water, we only installed detection in those process areas.

We did, however, require all personnel working in the facility to be H2S trained (Scott air pack use, etc) and made sure that personal H2S monitors were issued.

The entire facility was also designed with NACE compliance. These days that represents very little additional cost, since most equipment vendors take it into consideration in their standard products (particular valve manufacturers)

 

[toufik56]

I would recommend to establish the expected levels of H2s by using some sort of modeling. This will definitely give you an indication of where the acceptable H2S limits are (10 ppm during normal exposure of 8 hours). I am a little bit worried about this sudden increase of H2S in your gas and that may be interpretated as a variation of gas composition.
Best guess is that you probably need to prepare some sort of risk assessment and decide what is the worst case scenario before considering this issue as an overkill.

 

[senno]

Do anybody have experiences based on code & standard regarding the installation of H2s detector (i.e coverage area, proposed location, distance between each detector if we will install more than 1 detector)

rgrds

senno

 

[DeltaCascade]

Perhaps try OSHA??

 

[Cmo]

Trond,
Meeting NACE standard will be your biggest concern since you can have corrosion issues, stress cracking specifically. I believe the standard is that the partial pressure of H2S must be below 0.05 psia for sweet service equipment. That means at 600 ppm your overall pressure must be below 100 psia. Don't know where you are offshore but most likely above 100 psia, however your blended ppm is most likely less. There is technology out there to reduce small concentrations of sour gas.
Let me know if you have any questions. Good Luck.
CMo

 

[SooCS]

For H2S gas detection coverage and other issues related H2S, you might want to refer to API RP 55.

 

[d23]

Trond:

Please don’t misunderstand this post, because I’m not trying to be critical.....

Would you personally want to work in close vicinity of that wellhead every day as do the operators on the platform knowing the possibility?

If this well is in federal US waters a few things to consider:

1. You can check “MMS.GOV” and do a search for H2S regulations.
2. If someone gets hurt due to known H2S levels and you have no detectors you will spend years and millions in court due to liability.
3. You said it is in a well ventilated area. H2S is heaver than air. On a calm summer day people on a work boat or supply boat will be exposed to possible lethal levels.
4. Point being your liability exposure is very high if US courts are involved.

You may want to consider the tubing in the well. As most people have pointed out stress and cracking is a problem. If you’re using something like J-55 tubing you can expect tubing leaks. These tubing leaks will lead to casing degradation. In time the gas production may still be economical, but due to tubing and casing repairs needed the well will need to be plugged. I would try and find out why the H2S is increasing.

H2S monitors are not as expensive as people or well problems.

Good Luck!

 

[d23]

Trond

I deal with H2S on a very limited bases. Reading your question and some of the replies I decided to look for myself. I apologize for the length of this reply, but it is some of the info that I found.

First:
If this is US inland waters you may have "state regulations" involved that needs to be addressed. If it is US in federal waters MMS is involved. In both cases OSHA will be involved as DeltaCascade stated. I currently live and work in the US so this reply is what I perceive to be appropriate in the USA.

My first OSHA referance can be found at this link:

http://osha.gov/pls/oshaweb/owadisp.show_document?p_table=INTERPRETATIONS&p_id=21093

This is a "FAQ type response" dealing with working around open hatches. This is not your immediate concern, but OSHA does state very clearly there are no specific standards with regard to monitoring H2S.

Quote:
"Since OSHA has no specific monitoring requirements for H(2)S, the employer is responsible for determining what type and frequency of monitoring is appropriate to determine employee exposures, based on the nature of the hazard."

There is also information about working on wells and acceptable levels and regulations of what must be done.

This link is:

http://osha.gov/SLTC/etools/oilandgas/general_safety/h2s_precautions.html#No Hazard Area

The hazard conditions are (Quoted):

"No Hazard Condition:
Any well that will not penetrate a known Hydrogen Sulfide formation would be categorized as a No Hazard Area. Special Hydrogen Sulfide equipment is not required.

API Condition I - Low Hazard:

Work locations where atmospheric concentrations of H2S are less than 10ppm.

API Condition II - Medium Hazard:

Work locations where atmospheric concentrations of H2S are greater than 10ppm and less than 30ppm.

Condition III - High Hazard

Work locations where atmospheric concentrations of H2S are greater than 30ppm."

For each condition they specify in very clear terms what is required by OSHA. As an example for a medium hazard the requirments are:

„± Keep a safe distance from dangerous locations if not working to decrease danger.
„± Pay attention to audible and visual alarm systems.
„± Follow the guidance of the operator representative.
„± Keep all safety equipment in adequate working order.
„± Store the equipment in accessible locations.
„± An oxygen resuscitator.
„± A properly calibrated, metered hydrogen sulfide detection instrument.

At this point I am a little confused. For open tanks you are not required to have a monitor, for an open well you are. I'm sure any lawyer could rationalize this.

You may want to look at this link for a way to determine the corrosive protection you require:

http://www.nacestore.com/nacecom/pr...=02241+PREDICTION+OF+CORROSION+IN+SLIGHTLY...

Hope this helps!

 

[SooCS]

I am not a corrosion specialist, but I do know if the partial pressure of H2S exceed certain value as CMO has pointed out, 5 psi, H2S reacts with Fe to form FeS and H2.

This will lead to various types of damage to steels which include blistering, sulfide stress corrosion cracking (SSC), hydrogen induced cracking (HIC) and stress oriented hydrogen induced cracking (SOHIC).

Dry FeS ignite spontaneously when expose to air, especially when the vessel or the pig trap is open.

Offcouse all this cracking issues will not happened if the steel material has been normalized and tested for hardness not less than some magic number. I believe it is grinell 22?

I did come across one platform which had a similar problem though it H2S content was much lower. They have done extensive inspections and testings and concluded their facility is okay and proceed to produce.

 

[Trond]

Dear All,

thanks for the feedback. First of all, let me just start by saying that this platform is in SE-Asia. It is a wellhead platform, bridge-linked to other platforms. The wellhead area is open on one side, and is grated on all levels. Hence if you stand in the well head area, you look out at the sea on one side, and looking down, you see the waves about 15-20 meters below. Looking up, you see the sky, through the grating.

There is a boat landing on this platform, but I have never seen it used, as personell transfers take place by chopper, crane basket or incase of swingropes, at the living quarter some distance away.

I am aware of the corrosion issue, and we are monitoring this issue carefully. My question was more to do with the toxic properties of H2S in case of leakages.

The gas contains about 600 PPM of H2S. If this was the consentration in air, it would be a serious hazard. However, no person would be able to breath pure natural gas anyway.

My feeling was that (natural) gas detectors would pick up any leak before H2S became a concern. If the weather was still, and the gas happened to have exactly the same density as air and started to accumulate around the wells, I would be far more concerned about an explosion than H2S poisioning.

I (and a few others) still think gas alarms would be sufficient, but I am keen to hear if anyone thinks otherwise (or if you agree!).

Trond

 

[SooCS]

I think you have misunderstood, the danger of H2S.

H2S as you probably know is has a rotten smell but you can smell it when it is a few ppm. At an environment of least then 50 ppm of H2S for a few minutes, it will make you throw out. At higher concentration like 50 to 100 ppm, you may smell it for a few seconds and the it knock out you sense of smell. At about 200 ppm, it can knock you out unconcious and if you are not rescue immediately, you are dead. Smell H2S at concentration of 500 ppm and higher, you are dead.

As for natural gas, as long as there is enough O2 in the area, you can survive.

As you have indicated, a well ventilated area and the content of less than 600 ppm in the containment system may not be that risky. A small leak will probably provides enough concentration to kill. In any case, I would recommended you do a consequence analysis to see what kind of risk you are taking.

Best of luck.

 

[d23]

Trond

I see your point and am sorry for my previous post. Two quick points:

1) If you have electrical appliances such as lights on this facility a small H2S leak will cause very rapid degradation of the copper parts. That would be my first concern.

2) Assuming the platform is galvanized steel. A small leak could eventually be a problem, but considering open air I doubt we would see a problem in our lifetime.

Just my personal opinion!

 

[kbander]

Hi guys,

I hate to preach, but...

When dealing with H2S, your first concern is to the workers, not other parts that will be exposed during a leak.

As pointed out, a leak with 600 ppm H2S is extremely dangerous. Also, mentioned above, H2S is heavier than air, and you can't rely on your sense of smell to keep you out of trouble. I would recommend that anyone working in areas where they could be exposed to concentrations greater than 10 ppm should wear a personal H2S monitor. If you are sampling or draining in these areas, continuous monitors may be necessary.

Someone should check, but I though that a worker can be exposed to up to 10 ppm for 8 hours, and 15 ppm for something like 2 hours max. (at 300 ppm, dangerous to life in 30 minutes). This is probably slightly different for different locations, but the numbers are based on common knowledge regarding the effects of this deadly gas.

All I'm saying is leaks happen...sometimes big ones. Please protect your workers. Also keep in mind that many people have died trying to rescue those downed by H2S...because they went in without proper PPE.

Regards,

Bob

 

[Cmo]

Trond,
I deal with processing and sweetening marginally sour gas throughout Western Canada in concentration of H2S similar to yours as well as +/- an order of magnitude.
While all gas plants and most remote locations have lel monitors on the ceiling and H2S monitors on the floor it is mandatory for all operations to have personal monitors for detection. Redundant but worth it.
I would install monitors and alarms for H2S, personal and static. Due to the density difference b/w Nat gas and H2S there is a tendency for H2S to collect in low lying areas. As you mentioned there is grating but for $1000 US/monitor wouldn't you rather be safe than sorry?
Hopefully you have been able to produce the gas while having this discussion. If its shut-in than it seems like a no brainer.
Good luck.
CMo

 

[important]

Curious to know what could be done to reduce H2S level to safe limit fron NG? Alarms will help in identification but interested in available processes to reduce H2S from NG.

 

[Cmo]

There are many ways to sweeten varying in capital and op costs...what's your concentration, gas flow and pressure?
CMo

 

[important]

Cmo; Thanks for picking up this question.

Gas contains about 1/2% H2S with flow rate of about 200MMSCFD. Pressure is about 30 bar. I don't know if incenerator will be an alternate and acceptable environmental solution instead of spending $$ on SRU/TGTU....Thanks.

 

[Trond]

There are chemicals that can be injected into the stream to absorb the H2S. We did a field try with a Nalco absorbent, but the amounts needed to reduce our H2S significantly was too high (i.e too expensive) to make it an economically viable alternative.

Trond