This came to me from a reader.
49 acres of “We all Fall Down.”
The “Smackover” field in Navarro County represents an example of permitted H2S for EOR scheme that I find so worrisome. – the only confirmed example I have found so far.
Two producing wells at the site. Waste H2s is injected into Well #2 so that Well #1 can be re-opened. 500ppm radius for worst case doesn’t impact any roads, etc, so there is no trigger for public hearing. Application approved without opposition by TRC in 2010. 825 foot radius is just over 49 acres by my math.
note: these are not ppm levels being injected. these are percent.
http://www.rrc.state.tx.us/
meetings/ogpfd/ogpor36/05- 67398-r36pdf.pdf OIL AND GAS DOCKET NO. 05-0267398
______________________________APPLICATION OF O’ RYAN OIL AND GAS TO AMEND PERMIT NO. F-15381 TO
ALLOW DISPOSAL OF OIL AND GAS WASTE CONTAINING HYDROGEN SULFIDEGAS INTO A FORMATION PRODUCTIVE OIL E OF AND GAS AND FORAUTHORIZATION PURSUANT TO STATEWIDE RULE 36 TO INJECT FLUIDSCONTAINING HYDROGEN SULFIDE IN THE BURNETT-SLOAN UNIT WELL NO. B2 IN THE TROOPER (SMACKOVER) FIELD, NAVARRO COUNTY, TEXASO’ Ryan plans to inject a mixture of 46.3% H2S and 46.5% carbon dioxide (CO2) into the Burnett-Sloan Unit Well No. B2, between the depths of 9,294 feet and 9,410 feet, which includes the entire Smackover formation. This proposed injection will allow the Burnett-Sloan Unit Well No. B1 to be brought back on production, increasing recovery from the field.O’ Ryan plans to inject a maximum of 1,550 MCFD of H2S and CO2, with a maximum surface injection pressure of 4,500 psig. It is estimated that the average daily injection volume will be 1,400 MCFD.The 500 part per million (ppm) radius of exposure (ROE) for the subject well is 825 feet and the 100 ppm ROE is 2,020 feet. The radii of exposure are calculated based on worst case scenario of a injection wellhead blowout with maximum escape volumes and hydrogen sulfide concentrations. There are no public roads, residences or businesses within the 500 and 100 ppm ROE.Y’all are nuts.
As I’ve mentioned before, industry uses carbon disulfide in fracking so why not hydrogen sulfide? Those sulfides are such great solvents and it’s a good way to get rid of junk you don’t want.
They use H2s gas for enhanced recovery in Canada too.
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You bet this is a VERY DANGEROUS situation for just the quick list of things below:
1. Highly concentrated acid gas stream, seem to be used for secondary recovery. Is the second well an oil or gas well?
2. Highly corrosive acid gas stream, will need special metals in the entire flow stream. Bet they will go on the cheap here.
3. These ROE’s are usually calculated based on level, clear surface conditions. They do not consider valleys or creeks, or trees, etc, etc. Look at the actual terrain where the nearest people live or there are public roads and see if the acid gas can flow down creeks, etc. It’s heavier than air and will gather in low places and move when the wind picks up, etc.
4. If you think that such an acid gas stream cannot get loose and kill some people, study the Denver City case where it got loose in 1975 and killed nine people.
5. If the RRC is involved, know that they are very permissive and do not control much of anything at all. For instance, the SWR 36 pressure testing requirements are little more than pressures required for public water supply lines, etc.
The Smackover field is a very sour formation as far as I know.
Also, was wondering what else is being injected? Using the numbers in the post, there’s 7.2% of other crap that is being injected! Would be good to ask the operator what is included in this extra 7.2%. Bet it’s not nice stuff!!!
It’s a trade secret so we can’t know.
Sharon, thanks for posting this. Since sending you this email, I did come across that TRC list of sour gas injection sites I had been searching for.
ttp://www.rrc.state.tx.us/meetings/ogpfd/ogpor36/r36indx.php
I count something like 18 sites total. Interested parties are encouraged to take a look at some of these applications. The link below is to one I found particularly interesting. It involves my old dear friends at Unocal, and might help shed some light on the recent history of acid gas injection in Texas:
http://www.rrc.state.tx.us/meetings/ogpfd/ogpor36/r36pfd/8A-22023p.pdf
“For its CO2 injection, Unocal purchased CO2 that initially had a H2S content of 10 ppb. . . .
“New sources of CO2 entering the distribution line from which Unocal purchases its gas for injection, have greater concentrations of H2S than the earlier sources. By June of 1999, the percentage H2S content in the purchased CO2 for the Reinecke Unit reached 127 ppm.”
“If this application is denied, Unocal will have to cease its tertiary injection program. The tertiary program to date has been a technical success but has not yet been profitable. Any alternate means of disposal for the H2S, would increase the cost of the project and cause immediate cessation of tertiary recovery operations.”
So, If I have this straight, Unocal started off injecting H2S at a concentration of 0.010ppm. By 1999 that figure had increased to 127ppm. As of 2010, TRC is now permitting H2S injection for EOR at 460,000 parts-per-million at some facilities.
That seems like alot of parts to me. But I don’t know.
I’m just sayin.
I dd an open records request for Chesapeake’s MSDS sheets for “drilling” and “well prep” and they presented NBTEX and H2S amonst other things too…this doesn’t include the fracking MSDS sheets.
This was for the the drill site within 2,500 feet of the Dallas Cowboy Stadium.