Replies to This Discussion

Permalink Reply by Dash Riprock lll on March 30, 2013 at 15:45

Guess I just wondered why the well is permitted for a good bit deeper than where it seems the Austin Chalk would be in that area. Maybe this is common practice.

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Permalink Reply by John Parker on March 30, 2013 at 17:50

Dash:

In response to your questions I offer the following:

“If the lease includes all formations, but the request specifies Austin Chalk, does it matter?”

MS Onshore will most likely first drill a vertical section of the well to at least the base of the Austin Chalk and evaluate the Austin Chalk formation via electrical logs and probably some core analysis etc. This is their “science portion” of the work before they decide where to actually land the lateral into the Austin Chalk, which actual depth of landing the lateral, would be based on what their science analysis tells them.  However, if for some strange reason the Austin Chalk did not look very promising per their analysis they might scratch their heads and think about other possible options, which leads into your next question. 

“Does an 11,500 foot TD well in this 5N2W location penetrate the TMS too or is that just Austin Chalk depth?”

The Austin Chalk formation is positioned above the TMS so drilling to the base of the Austin Chalk would not penetrate the TMS. However, I believe that drilling down to 11,500 ft. in that area, will take them down to the TMS. In as much as the TMS is not much further down and if the Austin Chalk did not look very good it is possible that MS Onshore might decide to evaluate the TMS via some science work and if they liked what they saw they could potentially drill a horizontal leg into it and complete in that formation.  Another reason that some operators drill deeper during the first “science wells” has to do with their micro seismic testing which is basically, actual down hole seismic tests from one well to another that are in close proximity to each other. This gives them much better seismic data to interpret the natural fractures and other geologic features of the formation than can be achieved from surface seismic.   All they would have to do is amend their drilling permit with the MOGB which is done quite frequently by operators drilling wells and is easy to do.

“Is it just a forgone conclusion that the TMS is not a viable producing formation this far north?”

No, that decision is yet to be determined because no horizontal TMS wells have been drilled this far north to date to either confirm or condemn the potential production viability of the TMS formation this far north. However, there are some interesting observations that one can now make based on recent data that has become available. (Assuming one turns off Dancing with the Stars and does some digging into these matters LOL)

(a)  The 3 most successful TMS wells drilled to date are the Goodrich Crosby 12H, and the EnCana Anderson 17H and 18H.  The Crosby 12H has been flowing for approx. 60 days now and has already produced between 50 and 60 thousand barrels of oil to date.   All three of these wells are the most northern (updip) TMS wells drilled thus far.  These wells are far outperforming the more southern deeper wells.  However, that may have a lot to do with the fact that most of the deeper southern wells were drilled by Devon who did not do a very good job of drilling and completing the wells in the opinion of “industry professionals in the know”   

(b) The Cranfield Oil field has been one of the largest producing conventional Tuscaloosa Oil Fields.  Prior to Denbury’s recent CO2 injection recovery efforts, Cranfield produced around 62 Million barrels of oil in the 1950s and 60’s from the Tuscaloosa Sand formation which sits just below the TMS shale.  This conventionally produced Tuscaloosa field is much further north than the three best TMS wells drilled to date.

Hmmm, where did that oil come from ???  Was the TMS formation the source rock that produced this Tuscaloosa oil?  Or was it the Washita Formation that sits just below the Tuscaloosa, that is the source rock?  Or was it a combination of both contributing oil, which pooled into the relatively permeable and porous clean Tuscaloosa sand found in the Cranfield Oil Field.  Some source rock undoubtedly produced this oil; the question is how far the oil migrated from the source rock.

If it came from far away, that would rule out viable source rock horizontal wells being drilled in the local area surrounding Cranfield.  However, if the oil was generated from source rocks relatively close by and only migrated a short distance via natural fracturing that mother earth’s natural forces produced, it is quite possible that horizontal wells drilled into those source rocks could be highly rewarding and lead to a boom for Adams County.  

See the attached file: Cranfield 350ft Marine Mudstone. Go to page 17 and look at the electric log and Denbury’s labeling of the Marine Mudstone.

You will see that it shows the Tuscaloosa Marine Mudstone from approx. Elevation 9,875 to 10,250.  Half of this marine section (approx. 175’net) is at or above 5 Ohms of resistance on the deep induction electric reading which is considered (at this time) to be the cutoff point of productive TMS formation.

According to Kirk Barrell’s excellent data on the TMS, which information is readily available on his site Amelia Resources, the current areas of interest need a minimum of approx. 100’ thick of net TMS that is 5 Ohms or higher in resistivity to be economically viable for an operator to produce.

Based on the two facts presented immediately above, I believe from my observations to date, that the area starting around Woodville to as far north as the Cranfield Oil Field (Natchez) could have a high probability of being very productive for TMS oil production.  Denbury’s own published data, combined with the other published data/criteria of what constitutes prospective TMS acreage, strongly correlates this probability.

It is well known that the first movers in the Eagleford started development to far south (dry gas window). Over time as operators drilled the northern updip areas they realized that very economic wells could be drilled and produced, some of which was because of the shallower depths encountered.

I have also attached a Map for the reader’s convenience that shows the actual location of the MS Onshore Pintard 17 H Austin Chalk well in relationship to the Crosby 12H.

However, one has to realize that the current operators in the US are stretched very thin right now trying to develop up the various plays around the country which acreage positions in these plays has increased enormously in just the last few years. The huge E&P capital requirements needed to develop the existing plays out has most all of the operators struggling for funding to get the enormous task done.  This is one of the reasons that TMS has not accelerated as fast as say the earlier Bakken, Haynesville or Eagleford plays.  Simply put, most of the operators plates are currently full and until they work off some of that load, things may continue to move slowly in the TMS.

Also Dash, I replied to your PM to me yesterday and sent you an email to your email account. You might want to check and make sure you got it (may have went into the spam folder) as I did not get a reply from you as to the questions you had.

Anyway, hope this information is of benefit to you and all of the readers interested in these matters.

~~John

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Permalink Reply by Joe Ring on April 8, 2013 at 10:02

I. Phoenix Energy, Inc. and Great West Energy & Exploration, Inc. did two (2) 2600' laterals in the chalk at Esperance Point Field, Concordia Parish, Louisiana in 2003.  Both laterals were non-oil productive and geologicly described as unconsolidated and mushy.  That data was taken from the mud loggers on site.  Tried to ge them to deepen into the Tuscaloosa Sand but to no avail.  Interestingly, the laterals that we did in Section 8, T5N-R9E are almost on the exact Latitude with the proposed wells in Adams County. 

J. Ring

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Permalink Reply by John Parker on April 8, 2013 at 12:02

Joe Ring:

Thanks for sharing that information with us. I will take a look at that data. I believe you were making the right decision to deepen into the Tuscaloosa sand. Too bad they did not follow your recommendation.

The tight "Eaglebine" sandstone facies are being very successfully produced now out in East Texas using horizontal technology combined with frac jobs.  I suspect that could also possibly be the case in Adams County and surrounding areas as they share geological similarities to the Eaglebine.

Hopefully, one of today’s modern Operators will drill some horizontals in the previously “too tight” for conventional production, Tuscaloosa sandstones in our area.  These sandstones typically have much higher porosity and subsequently (available oil storage space) than shale formations, but did not have enough permeability to permit conventional commercial flow rates.

It is highly likely that an oil saturated Tuscaloosa tight sandstone formation horizontal well would significantly outperform an oil saturated Tuscaloosa Marine Shale formation horizontal, simply because it would contain a higher OOIP (Original Oil In Place) volume and should be much easier to frac than a shale formation.  Additionally, it is highly likely that the fractures would also be less likely to close in than fractures created in the shale formations.

Time and the drill bit will tell of the potential merits of horizontally drilling and fraccing the tight Tuscaloosa sandstone formations.  Let’s hope that it is sooner than later.

Thanks once again ~~ John

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Permalink Reply by John Parker on March 30, 2013 at 18:06

Dash:

It did not look like the files attached to my last post some I am sending them again.

Attachments:

• Cranfield 350ft Marine Mudstone ndx_hovorka.pdf, 801 KB
• Map Natchez Pintard 17 H Crosby 12-H Wells March 30th, 2013.pdf, 259 KB

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Permalink Reply by Dash Riprock lll on March 31, 2013 at 3:07

You have tripled my geology knowledge base right there. Thanks very much----it is very interesting. The use of the term mudstone rather tham shale---are those interchangable or does mudstone imply a higher clay content, less frackable layer?

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Permalink Reply by John Parker on March 31, 2013 at 4:14

Dash:

Dan Jarvie is one of the top Geochemistry guys out there. Lets see what Jarvie has to say:

“The highest flow rate systems are hybrid systems where mudstone is intermittently mixed with siliceous, carbonate, or silty lithofacies. Examples of this system type are the Haynesville, Bossier, Marcellus, Lewis, and Montney shales.

Shale-oil plays are mudstone systems containing producible oil (not oil shale systems requiring heating of organic matter). These are subdivided into three system types consisting of highly fractured, hybrid ,or mudstone shale-oil plays (e.g., Monterey, Bakken, and Barnett shales, respectively). Bakken tight oil producible reserves are estimated to amount to 5 billion barrels given present day technologies for development.”

I have attached a Jarvie report from which this information was obtained. I took the liberty of highlighting the section I referenced above. This document contains significant technical insight into understanding these "shale systems"

Jarvie has a ton of additional excellent work out there that one can easily source if you want to be on the cutting edge of the current understanding of these formations (as presently understood by the "experts").

So what do you think might have possibly been the source rock that produced the oil at Granfield after looking at the Denbury (Granfield Log) which confirms the presence of some good looking high resistivity mudstone when correlated with the data Jarvie presents.?

Hmmmm, pretty interesting association to me, especially with the fact that Granfield produced 62 million barrels of oil conventionally, prior to Denbury's current CO2 efforts.  Also, the thermal temperature at the depth the Cranfield mudstone exists is in the correct temperature range to have generated the oil.

The "hydrocarbon kitchen" from the upper LK (Lower Cretaceous) to the top of the Upper Cretaceous up as far north as Natchez looks as promising as the good stuff down south around the Crosby and Anderson wells from data I have reviewed. However, I am just an "armchair geologist".

However, if it does happen, remember where you heard it first. LOL.  Maybe I might get a field named after me in recognition of my early public disclosure of these infered items of interest. LOL.

Well you can shorten your hunt for Easter Eggs and dive into the hunt for where the potential future sweet spots of production in our area might be as Jarvie's information will keep you studying and learning for hours.

Thanks ~~ John

 

 

 

Attachments:

• Better Oreo Cookie 002 ndx_jarvie HIGHLIGHTED.pdf, 4.6 MB

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Permalink Reply by david crocket on March 31, 2013 at 5:03

Having an interest in the TMS makes you wish that you had gone to school to be a geologist.  I wish that I knew more.  Sounds like you have done your homework, John. 

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Permalink Reply by John Parker on March 31, 2013 at 5:41

I very rarely watch TV as I personally, view much of the content as a pure waste of time and mainstream news media has degenerated into nothing more than a propoganda machine, with very little reporting of real factual news.

That being said I spend most of my spare time educating myself with information that can potentially further my knowledge and understanding of subjects of interest that have a direct bearing on my life.

Yes, I have spent thousands of hours getting up to speed on the where, when, how of the TMS and other plays as they may relate to the potential events and prospectivity of the emerging TMS play.  There are not many bright sectors of our economy that I see. However, the TMS does have huge economic potential for all involved should continued development and success occur. 

All of the above said, it is also my perception that folks living in this country really need to start paying attention to recent activities in our nation and around the world which threaten our liberties and freedoms we have enjoyed for so long and have taken for granted.

Gonna leave it there, so as not to offend or violate the topic of this thread.

Thanks John

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Permalink Reply by Dash Riprock lll on March 31, 2013 at 13:03

Looks like Dan Jarvie became chief geochemist for EOG last month. I will read what I can find of his, hopefully understand a little. In the paper above, I don't see a key. What is the designation of the reserve "area 45" on the map that covers a portion of LA, MS, AL? This is north of most of the TMS fairway.

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Permalink Reply by david crocket on April 1, 2013 at 2:37

Doesn't sound too good for people who are leasing to eog.  (toc meaning???)  hopefully, he will give it a try in rapides parish.

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Permalink Reply by John Parker on April 1, 2013 at 2:54

ShaleGeo:

Given the "fact" that Jarvie is now working for EOG, why would EOG continue (currently as of this post) to be leasing in the TMS. Seems like Jarvie would inform his new employer of this fact to feather his nest so to speak.  Word is: that EOG is beginning to think and look east of the Big Muddy into Mississippi for acreage position to expand its TMS footprint.  EOG is presently permitting additional TMS wells in Avoyelles.

Additionally, the not enough TOC does not reconcile with the 1 Billion barrels plus of conventional Tuscaloosa production that has occurred in Mississippi and Louisiana, assuming on my part that the TMS is the source rock for this oil. Even if the TMS is not the source rock, it would appear that some relatively close source rock did have enough TOC and thermal maturity to cook the kerogen into high gravity light oil.

Additionally, the Anderson 17 – 18 H, and now the Goodrich Crosby 12 H all appear from the data to be highly economically commercial and are ginning out the oil on par with good Eagleford type wells.

Also, both EnCana and Goodrich have released TOC data in their company presentations from their TMS wells, which indicates TOC content ranges very comparable to other successful oil plays.

If Jarvie was of that opinion in 2011, it would appear that it may have changed, simply because of EOG's current leasing/drilling actions and the results from some of the wells (not all) thus far drilled in the TMS.

I would be very interested in your professional rebuttal.  Have I missed something or am I looking at this all wrong?

Thanks John

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