Natural Gas Cleaning Costs

[KeyboardWarrior + 527]

Does anybody know the cost per thousand cubic feet of desulfurization and water/nitrogen/hexane,butane, etc. removal? I've spent too long reading useless pdf's. Most of them from the 1900's. I figured this forum would have some individuals who could help me out. 

[Eric Gagen + 713]

There is an enormous range here depending on the constituent chemicals in the feedstock gas, and exactly which ones you want or need to remove.  It can be a source of costs or of profits depending on the situation 

 

It can be exceedingly expensive where large amounts of H2S and CO2 have to be removed, to the point where it is no longer useful to continue producing the gas. 

Conversely, separation on a sweet rich gas stream can be more profitable than the gas itself because the ethane, propane and natural gasoline which is separated out sells for a higher price than the natural gas does.  In some extreme cases the gas itself is flared/disposed and only the valuable extracted liquids are retained. 
 

To get a reasonable answer to your question you have to specify what is in the gas to begin with, how much of it is being produced/processed per day, and exactly where in the world it is located, since local regulations and product demand change the economics enormously. 

Edited July 16, 2021 by Eric Gagen

[KeyboardWarrior + 527]

8 hours ago, Eric Gagen said:

To get a reasonable answer to your question you have to specify what is in the gas to begin with, how much of it is being produced/processed per day, and exactly where in the world it is located, since local regulations and product demand change the economics enormously. 

If I gave you example ppm's of contaminants, would you answer my question? 

Let's go with the Midwest for location. 

Edited July 17, 2021 by KeyboardWarrior

[Eric Gagen + 713]

1 hour ago, KeyboardWarrior said:

If I gave you example ppm's of contaminants, would you answer my question? 

Let's go with the Midwest for location. 

I'll try - I'm not a midstream expert, but I'll give it a go, and perhaps someone listening in on this thread will have something to add as well.  I can probably better calibrate my answer with a couple of days of research. 

[KeyboardWarrior + 527]

1 hour ago, Eric Gagen said:

I'll try - I'm not a midstream expert, but I'll give it a go, and perhaps someone listening in on this thread will have something to add as well.  I can probably better calibrate my answer with a couple of days of research. 

I'm wondering, for instance, about reducing hydrogen sulfide from 10 ppm to 5 ppm. 

[Eric Gagen + 713]

My source is this PHD thesis here https://central.bac-lac.gc.ca/.item?id=MR50040&op=pdf&app=Library&oclc_number=710885018

His study is for central Canada, which aside from the fact that he uses Canadian dollars is generally the same conditions as the Midwest of the US (indeed the processes, corporations, and inputs he works with are typical US suppliers) 

His operating costs come out to ~ $0.10 US dollars per MCF (1,000 SCA) of natural gas per day.  This is from pages 62 and 63 of his report.  The capital cost from the same source is ~ $2,200 US per MCF of natural gas capacity of the facility.  
 

he assumes a gas inlet stream with 50 ppm and some CO2 also, so the costs for your system would be less, but how much less I’m not completely confident.  The most likely scenario is that capex remains the same, since the plant still has to exist with all the same equipment  but opex is ~ half for your 10 ppm scenario so $0.05 per mcf/day used  and $2,200 per mcf/day capacity constructed.  
 

over the course of a useful facility life of 20 years, with no discount rate the total cost would be ~ $500 per mcf for operating cost and $2,200 per mcf of capex for a total daily cost of $0.37 per mcf per day 

This sounds about right based on rule of thumb.

note that this is the cost to remove ALL the H2S - nobody sets up to only take out half. If you really did want a final output stream with 5 ppm then you would treat half the gas, then recombine it with untreated gas afterwards.  Don’t know why you would do that though.  Most pipelines won’t take gas with more than 1 ppm of H2S. That means gas with 5 ppm of gas still in it has effectively zero value. 

Edited July 18, 2021 by Eric Gagen

[KeyboardWarrior + 527]

@Eric Gagen Thank you so much. This is a huge help! 

 

[KeyboardWarrior + 527]

@Eric Gagen My knowledge on pipeline quality and H2S tolerance is incredibly limited. I'm looking at sulfur tolerances for steam methane reforming (H2S is a catalyst poison) and I wanted to know how much a chemical operator spends on cleaning their gas. Of course, it varies depending on the source and by region (as you mentioned). North Dakota ammonia producers buying gas from the wellhead undoubtedly have high operating expenditure for sulfur removal. 

[Eric Gagen + 713]

11 minutes ago, KeyboardWarrior said:

@Eric Gagen Thank you so much. This is a huge help! 

 

Glad it was helpful.  the PHD paper has an enormous amount of cost data in it (as well as describing how a bunch of this stuff works) so it's very useful as a general guide for costs and processes.  The numbers that I calculated jibe well with 'commonsense rules of thumb' for gas processing costs for contaminated gasses before the proceeds from sales of wet gas constituents.  

[Eric Gagen + 713]

11 minutes ago, KeyboardWarrior said:

@Eric Gagen My knowledge on pipeline quality and H2S tolerance is incredibly limited. I'm looking at sulfur tolerances for steam methane reforming (H2S is a catalyst poison) and I wanted to know how much a chemical operator spends on cleaning their gas. Of course, it varies depending on the source and by region (as you mentioned). North Dakota ammonia producers buying gas from the wellhead undoubtedly have high operating expenditure for sulfur removal. 

And that's where my knowledge ends - I know a lot about upstream operations, some about wellsite separation, a little about midstream and processing, and next to nothing of practical utility about refining processes.  Basically my knowledge is high at the point where the rocks meet the well, and drops off as you travel away from that point! 

[KeyboardWarrior + 527]

42 minutes ago, Eric Gagen said:

And that's where my knowledge ends - I know a lot about upstream operations, some about wellsite separation, a little about midstream and processing, and next to nothing of practical utility about refining processes.  Basically my knowledge is high at the point where the rocks meet the well, and drops off as you travel away from that point! 

I guess I'm totally opposite. There's a reason I'm studying chemical engineering and not geological engineering. 

[nsdp + 449]

On 7/16/2021 at 9:59 PM, KeyboardWarrior said:

I'm wondering, for instance, about reducing hydrogen sulfide from 10 ppm to 5 ppm. 

H2S has to be below 1.5 ppm  under the new  pipeline fugitive emissions quality specs for pipelines in Oil or NGLs.. Clean air rules as of 1 July You will need something other than amine to remove it.   Natural gas is now 3ppm under FERC quality specs for pipeline gas. Better check the party you deliver to for their own contract spec. Field gathering lines have more flexibility.

Edited July 19, 2021 by nsdp

[KeyboardWarrior + 527]

9 hours ago, nsdp said:

H2S has to be below 1.5 ppm  under the new  pipeline fugitive emissions quality specs for pipelines in Oil or NGLs.. Clean air rules as of 1 July You will need something other than amine to remove it.   Natural gas is now 3ppm under FERC quality specs for pipeline gas. Better check the party you deliver to for their own contract spec. Field gathering lines have more flexibility.

I was after a rate per ppm removal, but I wasn't thinking about the fact that the rate changes as you get closer to zero.

Going from 5 ppm to 1ppm costs more than going from 50 ppm to 25 ppm. My initial question was flawed, and as Eric pointed out, you simply remove as much sulfur as possible. 

[Eric Gagen + 713]

1 hour ago, KeyboardWarrior said:

I was after a rate per ppm removal, but I wasn't thinking about the fact that the rate changes as you get closer to zero.

Going from 5 ppm to 1ppm costs more than going from 50 ppm to 25 ppm. My initial question was flawed, and as Eric pointed out, you simply remove as much sulfur as possible. 

the amount of H2S present in a natural gas stream is highly variable.  I remember working up engineering stuff for some gas wells in the Florida panhandle that were making 60-70% (600,000 to 700,000 ppm) of H2S.

[KeyboardWarrior + 527]

8 hours ago, Eric Gagen said:

the amount of H2S present in a natural gas stream is highly variable.  I remember working up engineering stuff for some gas wells in the Florida panhandle that were making 60-70% (600,000 to 700,000 ppm) of H2S.

My Lord. At that rate you're better off producing sulfuric acid on or near site 😆

[Eric Gagen + 713]

27 minutes ago, KeyboardWarrior said:

My Lord. At that rate you're better off producing sulfuric acid on or near site 😆

maybe they would be - I don't know. Usually the H2S that is recovered as elemental sulphur from operations like this IS sold for sulfuric acid production, so you aren't completely off base. What I do know is that all the well servicing tubular goods we used for the project were strictly for displosal - we did the work, charged them for all the steel equipment that was exposed to the gas, then threw it away, because we knew it would fail if used again. 

I was involved in another project in Utah where we generated large volumes of H2S by dissolving sulfide scale with H2S gas.  We used high ductility low yield steel for that project successfully for 3-4 months before having completing the work and throwing it out.    

In all these cases and plenty of others we used a lot of H2S scavengers and complexing agents to at least partially reduce the odds of failure - nevertheless it's a constant battle.  I have done a LOT of work with a variety of metallurgies in many different H2S and CO2 situations.  

Edited July 20, 2021 by Eric Gagen

[nsdp + 449]

On 7/19/2021 at 9:25 PM, Eric Gagen said:

maybe they would be - I don't know. Usually the H2S that is recovered as elemental sulphur from operations like this IS sold for sulfuric acid production, so you aren't completely off base. What I do know is that all the well servicing tubular goods we used for the project were strictly for displosal - we did the work, charged them for all the steel equipment that was exposed to the gas, then threw it away, because we knew it would fail if used again. 

I was involved in another project in Utah where we generated large volumes of H2S by dissolving sulfide scale with H2S gas.  We used high ductility low yield steel for that project successfully for 3-4 months before having completing the work and throwing it out.    

In all these cases and plenty of others we used a lot of H2S scavengers and complexing agents to at least partially reduce the odds of failure - nevertheless it's a constant battle.  I have done a LOT of work with a variety of metallurgies in many different H2S and CO2 situations.  

Try removing H2S from a retrograde condensate reservoir like Carter Creek and Whitney Canyon in Wyoming. "Located in the Fossil basin area of the Wyoming thrust belt, giant Whitney Canyon-Carter Creek field has in place reserves of approximately 4.5 tcf of gas, 125 MMBO (condensate), and 24 million long tons sulfur. It is the largest gas field in the U.S. Rocky Mountains. "  Processing plants cost $250 million in 1981. That did not include the nitrogen injection plant.