Replies to This Discussion

Permalink Reply by Paul M. Hess on January 24, 2011 at 1:10

It appears from the Magnolia reporter article that the plant is to strip nitrogen from the natural gas they are producing in the field, primarily from the Cotton Valley as I recall. Different equipment and safety measures would be needed to strip and process hydrogen sulphide containing gas. So I doubt this plant will have any real affect on the Bussey wells future. It would take a well or two a lot more productive for an operator to even consider a hydrogen sulphide processing plants construction. But I, like many of you, will keep my hopes up that someone will find the coveted sweet spot with decent production.

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Permalink Reply by North LA on January 25, 2011 at 15:57

Thanks Tony.

Permalink Reply by BirdDawg, plain ole' idiot on January 25, 2011 at 15:57

Please correct me if i am wrong, but Pinebelt is not an operator.

It appears to me that they just buy leases.

So why would they have any effect on anything?

Permalink Reply by L Davis on January 25, 2011 at 16:31

Pinebelt is buying for a client oil company that will  probably emerage as the major player in the brown dense play or at least in the amount of acreage leased.  Don't you figure that this client company is very interested in every well drilled and will use their acreage to get an  interest in this well and gain access to all of the data.   Seems like it would be a lot less expensive than drilling their own well.

 

 

Permalink Reply by jeff boler on January 30, 2011 at 18:07

If Pinebelt owns a lease/leases within the drilling unit, then they could potentially have a great effect on many things, including a delay of the spud date to the very existence of the drilling unit. However, from the context of Mr. Allen's post, it appears that they have chosen not to exercise these rights and have struck a deal with the operator.

Permalink Reply by The_Baron on January 28, 2011 at 5:45

bump

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Permalink Reply by Terry L. Antee on January 28, 2011 at 9:10

The problem I see with the brown dense is that the porosity is 3% of less on all of the logs I have looked at.  Fractures add 1% to total porosity.  99% of 3% is a problem in that there is no place for the oil, gas and water.  Throw in a 20% recovery factor and unless someone finds a sweet spot with 9 to 14% porosity they are not going to make a comerical well.  I think Pinebelt is looking at something else besides brown dense.

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Permalink Reply by jeff boler on January 30, 2011 at 18:52

This is strickly a hypothesis:

 

With the 'brown dense' sequence of the smackover being such a prolific source for oil production from sediments across the GoM basin, and given the 'oil-prone' tendency of the organic compounds deposited within the brown dense, perhaps porosity might not be as key in this play as it is in every other known case. Please follow...

The brown dense is naturally fractured, but given the high concentration of calcium chloride in the surrounding formations, those fractures are likely to be completely cemented full of calcite. However, if a new fracture network could be established within the brown dense, supplying permeability to the formation, perhaps the natural generation oil (given the appropriate temperature and pressure) would be enough to establish a well which would continuously produced a predictable flow rate of hydrocarbons. Furthermore the reactions involved in breaking complex organics down into flowable hydrocarbons within a constant volume (a given amount of brown dense) would increase the pressure. This pressure increase would reach point at which it would hinder and eventually stop the reactions that generate the oil and gas. From this point forward in time, more oil or gas could only be generated at a rate equal to the rate of escape of previously formed hydrocarbons. Escape=free volume=pressure decrease=reaction progression=hydrocarbon formation. With the low porosity and the cemented fractures, it has been very difficult for hydrocarbons to escape the brown dense. Perhaps a well would facilitate a faster rate of hydrocarbon removal, thus lower reservoir pressures and enhanced hydrocarbon generation. This theory would be valid only in cases where the temperature was such that it allowed pressure to be the limiting variable with regards to reaction progression.

Personally, I doubt that these rates would be commercial at the present date, as I feel that fracking the brown dense would call for a rather costly frack-job, likely super-low ROP while drilling, and probably low production rates - as i imagine that nature wouldn't get in a hurry when converting algae/plankton into produceable hydrocarbons, even if we modified the reservoir conditions to as close to ideal as possible.

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Permalink Reply by Paul M. Hess on January 31, 2011 at 1:02

IMHO, the biggest problem with the production from the brown dense will be the overall presence of micropososity with lack of adequate permeability(for those unfamiliar with the term, permeability is the measure of a formations ability to allow fluid to flow through it). While natural fractures do exist, the extent, quantity and quality(openness) of those fractures should be high in order to first capture the expelled hydrocarbons and then hold them. Calcite sealed fractures will be useless as they will decrease the "reservoir capacity" during the time of hydrocarbon expulsion. The hydrocarbons generated in situ in the brown dense are what we will have to deal with in our lifetime and generations to come. It would need to be buried as deep as the shale that mainland is dealing with in the Burke-Phillips well to "squeeze out" those hydrocarbons trapped within its confineing matrix. It is my belief that the so called "sweet spots" do exist. It will be a logically driven awareness of the area that will help  to begin to nail those locations.

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Permalink Reply by Skip Peel - Mineral Consultant on February 4, 2011 at 12:18

Thanks for posting the completion report, tony.  Here's my take.

1.  Neither, it's how the completion was designed based on the science generated by tests.  It's short by HA standards but then again this ain't the HA.  With 5 stages the average length would be ~476, typical HA stages are ~300'.  Though we can judge the lateral length and number of stages, there are no specifics regarding the perforation clusters.  I imagine that's a learning curve, like lateral and stage length, that is only driven by drilling and completing wells.

2.  If I recall the site was approved for two 550 gallon tanks or about a 22 day capacity at this flow rate.  Filing for permission to transport can take some time to process so I think the request is out of an abundance of caution. 

3. Gas Oil Ratio (GOR) decreases with production.

4.  I can't speak for Brammer/Anderson but with transportion costs and royalties paid out, it's marginally economic IMO.  Also the gravity is lower than I expected (34) but then again that's getting above my pay grade and I'll leave that for another member to comment on.

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Permalink Reply by Skip Peel - Mineral Consultant on February 4, 2011 at 12:46

Depending on the lease language concerning shut in period, the well could be listed as Shut In - Productive for 12 to 24 months.  As far as I am aware operators never make investment decisions based on the benefits accruing to royalty interests other than their own. Yes, if the operator thinks they can drill additional wells in the immediate vicinity that will be improvements on this initial well.  We can judge what Anderson/Brammer think by what they do in the near future concerning additional wells.  The natural gas production here is minimal and basically has little or no value except as the "drive" mechanism for this oil reservoir.

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Permalink Reply by North LA on February 4, 2011 at 14:15

Thanks Tony. Looks like this was a test well. Most Eagleford shale wells are 12-15 stage fracs.

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