Replies to This Discussion

Permalink Reply by Skip Peel - Mineral Consultant on December 23, 2017 at 3:12

Charles, these are Austin Chalk oil wells.  Any associated natural gas will be considered a "by-product" and the volumes will likely be insufficient to justify a gathering and treating system, at least initially. 

Natural gas liquids commonly called NGLs are ethane, propane, butane, isobutane, pentane and pentanes plus.  No benzine.  NGL supplies have increased greatly with the advent of production from unconventional reservoirs.  Although we think of certain plays as oily much of the liquid volumes are condensate and NGLs.  The Eagle Ford Play is a good example.  Because NGLs were not generally plentiful in most oil plays and many operating companies were not interested in the capital costs associated with large scale production of those liquids, historically standard lease forms did not address them specifically.  For the same reasons, the State of Louisiana did not prioritize tracking NGL production.  Now NGLs are an important part of a company's profit margin in wet gas plays and the chemical industry has boomed because of the cheap feed stock costs.  The lack of process and regulations to track NGL production and the general lack of specific lease language covering royalty paid on NGLs is just one example of how the old rules do not work well in the age of unconventional reservoir development.

https://www.google.com/imgres?imgurl=https://www.eia.gov/todayinene...

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Permalink Reply by Craig Wascom on December 23, 2017 at 5:53

Great post Skip this is an area of leasing that now must be addressed.

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Permalink Reply by Skip Peel - Mineral Consultant on December 23, 2017 at 6:03

Yes, the state needs to change the way they require reporting of NGLs and lease addendums need to include clauses covering how royalty is paid on them.  However, I must stress that the issue of NGLs does not apply to the Austin Chalk in Louisiana at this time as far as I know.  As I mentioned above, there is little natural gas produced from the Eagles Ranch 14H and the oil is 43 gravity which is light but indeed oil as opposed to condensate.  If I recall correctly the API gravity range for condensate begins at 48 degrees and ranges higher.  Production of condensate is an indication of the presence of NGLs.

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Permalink Reply by Charles Jenkins on December 23, 2017 at 6:50

Thank you for the reply.  It is clearly stated, even for me.  Some of my experience from north Louisiana will not come into play in the Austin Chalk, should that develop.

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Permalink Reply by Dion Warr, CPL on January 2, 2018 at 18:56

Skip:

There are a number of examples of AC gas wells completed in western central LA.  A number of Burr Ferry wells were originally completed and continue to produce as gas wells.  Also, Masters Creek (and all nearby adjacent namesake fields) produced a significant gas component (although all or nearly all were classified as oil wells).

As far as NGL regs and tracking - in LA parlance, products or either oil (liquid) or gas, dependent upon state at defined temperature and pressure.  That is what is tracked and reported.  Water / BSW counts for testing but is not specifically measured in the SONRIS system.  NGLs inhabit the ethereal "in-between" - "Vapor" is gas, "Condensate" is liquid (oil).  The issue with NGLs becomes that of capture, separation and treatment - NGLs are not required to be split-streamed and sold.

In many cases, "rich gas" is simply sold at the marketing point for BTU content, unless either rejected (off-spec) or otherwise separated from the stream (via cryo-unit, separation and compression either on-site, at the field plant or otherwise transported as raw feed to a larger central facility).  In some cases, the producer (lessee) receives the benefit of NGL capture (which is sometimes passed to the lessor), in others, the purchaser alone receives it post-processing (no benefit to the lessor).

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Permalink Reply by Skip Peel - Mineral Consultant on January 3, 2018 at 1:28

The no benefit to the lessor part is where my concerns come in.  Thanks for the clarification, Dion.

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Permalink Reply by Dion Warr, CPL on January 3, 2018 at 4:23

Skip:

Also consider that NGL separation is not always profitable in the upstream model.  Concentrations needed would have to exceed the threshold of profitability in order to install the necessary equipment for producers to realize capture and revenue.  Specifically to your areas of interest, this profitability has been low to marginal, except as large gathering and transmission facilities.

This presentation (link) is dated (2012), but illustrates the problems of free-market effects on these product streams.  Most pertinent material begins Slide 20 and after...

In a forced (regulatory) environment, pressures can be put into place to incentivize NG and NGL capture (e.g., new North Dakota regs designed to reduce flaring and increase product takeaway).  But in NW LA (and particularly dry gas plays, ie. Haynesville) a "forced NGL capture" model and/or royalty burden on NGL components could have a chilling effect on future development.

Permalink Reply by John M Santamaria on January 3, 2018 at 3:49

I live across from the "Eagles Nest" and there is a very healthy flare of gas being burned off last night. For what it's worth.

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Permalink Reply by Craig Wascom on January 3, 2018 at 4:14

Dion

I think you really have a handle on this important issue. Could you please break this response down a little further for those of us without an O &G background?

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Permalink Reply by Skip Peel - Mineral Consultant on January 3, 2018 at 6:24

Dion, I understand the concept of ethane rejection and that sufficient volume is required for profitable NGL extraction.  Although the Haynesville Shale is not a good NGL source, much of the current CV and LCV production in north and northwest LA is wet gas with considerable profit potential for NGL.  Future NGL demand looks strong.

Permalink Reply by Dion Warr, CPL on January 3, 2018 at 10:43

Skip:

Although I appreciate the amount liquids component present in the wet gas side of the CV and LCV, these developments cannot be evaluated in a vacuum.  Other plays with sufficient (and in some cases markedly better) takeaway capacity with even higher liquids component exist and produce heavily laden gas streams which are rapidly soaked into the market.  NW and north central LA must compete with these alternative streams in the common marketplace.  It’s more than just ethane.  Propane markets are increasingly saturated which drives down demand.  The midstream and downstream facilities which have served as alternate capture and production points for these conpounds continue to produce into the market stream.  While developing markets abroad can soak up some of this supply (particular C3 and C4) there is a finite market for these products.

Particular to ethane, suitable transport infrastructure must be ramped up to transport and accept this stream from more, and more far removed, production points if one is to have any hope of fostering demand sufficient to warrant ethane capture above that which transmission companies can accept.  Even then, one can easily visualize a scenario where the bottleneck is merely removed further downstream to petrochemical facilities that can utilize this stream (e.g. Ethylene, PE, EO) which has significantly ramped up production in recent years but only to burrow into (again) a finite market for refined intermediates and finished product.

All that said - W TX and S TX continue to dump shiploads of NGLs as byproducts of their oil production.  They in turn supply much of the TX Gulf Coast refinieries and overspill into Lake Charles and beyond.  North LA can displace some of this market share, but not to the point of exhaustion of its available NGL stream prior to being priced out.

Craig:

The issue that Skip raises is a good one, in that producers do have options in being able to separate and/or alternatively market these products.  For most of the history of oil and gas development, oil was king (being easily transported, refined and used) and gas was a red-headed stepchild.  Once NG pipeline infrastructure and distribution advanced to a certain point where NG could be efficiently distributed to large portions of the population, it ascended to a point of prominence with which we have become familiar today.  NGLs were niche compounds with limited application and market, being neither oil nor gas but possessing properties of both.  Petrochemical processes and materials research has largely grown this market to the point that pre-shale revolution the margins on these products was sufficiently thin so as to make separation and selling this stream could become immensely profitable at times.  This is less the case today as shale production can produce a much broader population of hydrocarbons than conventional production generally did.  And although a producer has more access to modular units and facilities that can create such an alternate product stream, one still has to expend resources to separate the product and reach a certain purity, and then have the ability to transport it to a willing buyer.  For that, profitability and access is key.  Texas fields on the whole are currently better equipped at both, and their product streams in hot plays create more volumes of these compounds than Louisiana fields.

One could attempt to “create” a market by regulation (purposed either to separate, meter and sell more NGL) or by contract (provisions which either incentivize producers to produce these streams or penalize them for not doing so).  But this alone will not change current infrastructure constraints or market forces.

Permalink Reply by preston dixon on January 9, 2018 at 0:45

See Torrent oil apply for drilling permit for North Bayou Jack Field anybody knows about them

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