Replies to This Discussion

Permalink Reply by Paul M. Hess on May 4, 2012 at 2:41

It is my understanding that the initial well drilled in Lafayette Co., I think in S24-T19S-R26W(I think), tested quite sour (H2S), As did the Brammer well. I know from past experience(I was with TXO Production when they tested it vertically in the early 1980's) that the BDLS under Atlanta Field, where SWN drilled the Roberson well, is also quite sour. H2S will impact economics as to corrosion, added expense as to processing out the H2S and the current gas pricing being lower due to the H2S content.

Permalink Reply by Chip Sanches on May 4, 2012 at 5:05

Skip,

 

Does the H2S concentration of 60,000 PPM in the report indicate a sour gas problem (or potential problem).  I'm asking (in a layman's way) if there's a threshold PPM number above which H2S pesents significant production difficulties or complications.  I've seen no mention in Southwestern press releases or "calls" of an H2S "problem".  If true, I'm hoping that is good news.

Permalink Reply by Skip Peel - Mineral Consultant on May 4, 2012 at 5:31

Chip, I posted the report for comment by some of the experts.  I'm not up on H2S regs and operating cost considerations.

Permalink Reply by dbob on May 4, 2012 at 15:16

Chip

Don't know the specific number, but if its anywhere close to 60,000 ppm, the alloys used in the wells and piping to the processing plant have to be different to minimize development of brittle areas/reduce fracture risk.  Add monitoring, more expensive processing, etc. Potentially slightly offset by producing sulfur as a valued by product.  Produced oil would likely also be sour, and suitable for fewer refineries, and slightly lower value.  I've seen 150,000 ppm H2S gas produced, and think others may produce it higher elsewhere.    

Permalink Reply by Robert Carr Head on May 4, 2012 at 22:07

At the refinry the epa regs required below 20 ppm total sulfur for fuel gas for our funances and boilers. I do not recall the exact number but our in plant spec was 20 PPM for our process gases. We then cut that back with purchased gas which was typacaly 4 PPM total sulfur. which was mostly the added mercaptans which were added to give the gas an odor for leak detection. The H2S content at the customer end was almost always less than 1 PPM (I do not recall ever detecting any but I did not work that part of the lab on a regular basis.

I have zero experience or information about specs on the other end of the pipeline, but 60000 PPM will need treatment. 

Permalink Reply by Les Bamburg on May 5, 2012 at 7:52

Chip, where did the 60,000 ppm originate?  Was that ppm volume or ppm mass?  If the former that would equate to 6% which would be hard to believe.

Permalink Reply by Skip Peel - Mineral Consultant on May 5, 2012 at 7:57

Les, the figure came from the HS-1 report on the Roberson well.   It was 60,000 PPM. The links to the AOCG database time out quite quickly.  Here is a new link:

http://aogc2.state.ar.us/scripts/cgi/dwis.pl?COMMAND=9&SESSIONI...

Permalink Reply by Ed on May 5, 2012 at 9:06

Check the date stamp. Sep6,2011. ??

Permalink Reply by Skip Peel - Mineral Consultant on May 5, 2012 at 9:27

The Roberson well was drilling prior to Sept. 6 however it was in the early stages.  I'm not up on the B-41 regs as to when the HS-1 report is to be submitted.

Permalink Reply by obed w odom on May 8, 2012 at 16:59

I see in another document filed with the AOGC that SWN did not reach the 7000-ft level in the Roberson well until Sept 15, 2011. On this date Jeremy of SWN gave 12-hour notice to AOGC that they were 300 feet from 7000' and approaching the possible H2S zone. So when SWN filed the HS-1 report on Sept 6, 2011, they had not yet penetrated the H2S zone. Maybe the numbers they gave for H2S in the HS-1 report represented the worst-case scenario, which apparently did not materialize.

http://aogc2.state.ar.us/scripts/cgi/dwis.pl?COMMAND=9&SESSIONI...

Permalink Reply by Ed on May 8, 2012 at 17:53

The HS-1 Form has to be filed before operations commence.

"This form shall certify that the operator has complied, or will comply, with applicable provisions of Rule B-41."

"For new or modified facilities not covered by an existing HS-1, or where the modification would require an amended form, the
operator shall file a HS-1 at least 30 days prior to initiating the operation or construction"

Permalink Reply by Bill Meaney on May 8, 2012 at 15:24

60,000 PPM would definitely present logistical issues and would increase the cost of completing the wells.  

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