wood for the trees...

The market cannot see the wood for the trees…

I will mak an effort to summarise as best as possible (briefly) my thoughts on this well to date, but there is just so much going on, I could be writing for days…lol..but if you are truly interested, I suggest this “shortened version” it may be worth the read.

I will mainly concentrate on gas, although with oil confirmed in the Upper Ismay and the likelihood of wet gas from multiple formations all the way down, (some already confirmed in Barker Creek) condensates may well be a significant part of the equation here.

As I understand it, wet gas is likely to yield around 20bbls/mmcf in fluids…as such, even just 10bcf of wet gas will yield some 200,000bbls of fluids…and 100bcf will give up 2,000,000bbls! This is in addition to the Upper Ismay oil column which could potentially equal this again?

Anyway…comparisons are being made to Lisbon due to the obvious Leadville limestone focus, which is all very good, but for some reason it seems the market has completely failed to see the relevance already confirmed for a more realistic comparison to the giant Aneth Field.

In the end however, as I have said several times, I suspect we will eventually come to look on the Golden Eagle prospect as a unique play in its own right.

Following is a basic run-down on some of the regionally accepted “play types” that are perhaps the closest reference to what may well be going on at the Golden Eagle Field…I have only included the descriptions of the four more relevant plays for simplicity…there are many play types.

--

PARADOX BASIN PLAY TYPES:

Most of the production in the province has been from porous carbonate buildups (mainly algal mounds) around the southwestern shelf margin of the Paradox evaporate basin. The giant Aneth field, with more than 1 BBO in place accounts for as much as two-thirds of the proven resources in the province, and other fields in this primarily stratigraphic play (Porous Carbonate Buildup Play, 2102) account for much of the rest. Most of the other plays have a strong structural component, particularly the Buried Fault Blocks, Older Paleozoic (2101), Fractured Interbed (2103), and Salt Anticline Flank (2105) Plays. The Permian–Pennsylvanian Marginal Clastics Play (2104), Permo-Triassic Unconformity Play (2106), and Cretaceous Sandstone Play (2107), as well as the hypothetical Lower Paleozoic/Proterozoic Play (2403) which is described in Northern Arizona Province (024), are combinations of both structure and stratigraphy. The Fractured Interbed Play (2103) is an unconventional, continuous-type play.


2102. POROUS CARBONATE BUILDUP PLAY (Aneth Field)

This is primarily an oil play in the Paradox Basin Province and is characterized by oil and gas accumulations in mounds of algal (Ivanovia) limestone associated with organic rich black dolomitic shale and mudstone rimming the evaporite sequences of the Paradox Formation of the Hermosa Group. Most of the developed fields within the play produce from stratigraphic or combination traps. The largest oil field in the province, Aneth, is developed in this play. Many smaller "satellite" mounds in the vicinity of the Aneth field also produce oil from the play as do other fields with more of a structural component.

Reservoirs: Almost all hydrocarbon production has been from vuggy limestone and dolomite reservoirs in five informal zones of the Hermosa Group, in ascending order, the Alkali Gulch, Barker Creek, Akah, Desert Creek, and Ismay. The largest producers are the upper two zones, and they are the producing intervals at Aneth. Net pay thicknesses generally vary from 10 to 50 ft but may be as great as 100 ft; porosities are 5-20 percent.


2101. BURIED FAULT BLOCKS, OLDER PALEOZOIC PLAY (Lisbon field)

The play is based on the occurrence of oil accumulations in fault blocks involving pre-Pennsylvanian rocks, mainly in the salt anticline area of the Paradox Basin, and it covers an area of approximately 7,500 sq mi. Most of the structures are associated with the salt anticlines themselves and were growing at the same time that the salt was moving.

Reservoirs: Reservoirs are in porous dolomite or dolomitic limestone beds of the Mississippian Leadville Limestone and the Upper Devonian McCracken Sandstone Member of the Elbert Formation. Reservoirs are as thick as 200 ft, and porosity varies from 5 to as high as 25 percent in local cases. Permeability is generally low but is as much as several hundred millidarcies in places.


2105. SALT ANTICLINE FLANK PLAY

This play is characterized by association of gas- and oil-productive Permian- Pennsylvanian reservoirs along the flanks of northwest-trending salt anticlines in the axial part of the Paradox salt basin. The play area is approximately 7,500 sq mi. Salt anticlines consist of long northwest-trending diapirs or pill.ows of Paradox Formation salt over which younger rocks are arched in anticlinal form. The central, or salt-bearing, cores of the anticlines range in thickness from 2,500 to more than 14,000 ft; the anticlines are flanked by deep synclines (sites of salt withdrawal) that are filled with 10,000 ft or more of chiefly arkosic clastic rocks of the Permian Cutler Formation and a mixed sequence of clastics and carbonate rocks of the Pennsylvanian Hermosa Group.

Reservoirs: The main reservoirs in the play are pelletal and oolitic limestone and sandstone in the upper part of the Hermosa Group and arkosic sandstone in the Cutler Formation. Sandstone reservoirs are as thick as 200 ft. No data are available on reservoir quality; however, it is estimated that permeabilities may be as high as 1,000 millidarcies locally. Vertical communication between these reservoirs is common because of (1) well-developed fracture systems resulting from strong subsidence in the flank syncline, and (2) related salt movement and flowage into the adjacent salt anticlines.


2103. FRACTURED INTERBED PLAY (HYPOTHETICAL)
This unconventional continuous-type oil and gas play is oil prone throughout most of the Paradox Basin but is more gas prone to the east close to the ancestral Uncompahgre uplift; the reasons for this change in character are increased depth of burial and percentage of terrestrial organics to the east.

Reservoirs: The play depends on extensive fracturing in the organic-rich dolomitic shale and mudstone in the interbeds between evaporites of the Pennsylvanian Paradox Formation or carbonate and clastic rocks of the related cycles on the shelf of the Paradox evaporite basin. These shales and mudstones may be as thick as 130 ft but are more commonly less than 20 ft thick.

--

Now…pre drill prognosis declared an upside target of 3tcf assuming full charge over a net 319m zone in all targets…from the 600-1,200ha Paradox closures (197m vertical pay) down to the 1,200-2,000ha Mississppian closures (122m vertical pay).

Given the significant number of hits in the upper Paradox formations, it would appear comparisons to Aneth, which produces from these same zones is perhaps more appropriate?

I think people forget just how many gas “shows” were recorded all the way down at higher levels, ranging from 200 to 900 units background gas…and of course a few supercharged intersections of 2000+ units. In light of this I feel the “table” of potential productive zones, as provided by GDN is a little under-done and should be seen perhaps as more a summary of productive "zones", in which there may well be multiple productive horizons in each.

From announcement 20-10-06…“ A 40 foot thick sandstone unit, with the top 16’ gas-bearing (390 units), marks the top of the Barker Creek member (11,016 feet).”

Now…this has since been offered by the company as simply a “gas show” but also a likely producer (11016’-11030’ Barker Creek). The significance here in my mind is the 390 unit background gas reading for a potential commercial pay zone. In the same announcement, they state…

” Since last report, a further six gas shows, of up to 790 units (one unit equals 100 ppm gas), have been intersected, five in sandstone units of the Barker Creek member.”

None of these additional five zones (up to 790 units) were included in the initial 14’ (390 unit) Barker Creek zone, leading me to believe that for this level, we have a significantly larger net pay zone than has been suggested...the since zone marked for production on the charts is actually made up of a series of multiple horizons.

This pattern of reporting seems to be repeated at virtually every “gas show” from what I can see, leading me to believe there is significantly more net pay in the upper zones than people may realise?

Interestingly, there were sections of the Alkali Gulch, Barker Creek, Akah, Desert Creek, and Ismay which produced continuous background gas readings in the 200-700 unit range, for hundreds of feet in places…lol…did that sequence sound familiar? It should have; from the above metioned Aneth field description…

Reservoirs: Almost all hydrocarbon production has been from vuggy limestone and dolomite reservoirs in five informal zones of the Hermosa Group, in ascending order, the Alkali Gulch, Barker Creek, Akah, Desert Creek, and Ismay. The largest producers are the upper two zones, and they are the producing intervals at Aneth.

Of greater importance, the 6m Oil column in the Upper Ismay may as well be coming from an Aneth report…more significant also given they are on the far outer flank of this particular accumulation, suggesting it may well be filled to spill point?

Anyway, there have been many many “gas shows” in the well to date, which collectively seem very commercial…interestingly, the reporting of the significance of the various “gas shows” seemed to stop after the Alkali Gulch hit?

Further…if 390 units background gas has since been declared a likely "producer" from the Barker Creek formation, what are we to think then of 300 units background gas and 600 units trip gas currently being recorded in Leadville (and increasing!) over what appears to be significant widths?

Some further references…

From the 31 October announcement…“Significant gas discovery in Alkali Gulch zone of Paradox Formation”…

“Connection gas ranges from 2,000 to 3,300 units. Background gas has increased 40-fold to consistent levels of 500-900 units”

Compare to current levels of 300 unit background gas and 600 units trip gas in Leadville.

Then this from deeper down in the 6 November announcement..” New significant gas shows in Cane Creek member of Paradox Formation”…

” Two significant gas shows have been encountered, from 13096’ to 13104’, and from 13148’ to 13152’, in vuggy dolomite between salt horizons. The host dolomite is the best quality reservoir rock so far seen in this well. The well continues to have consistent elevated levels of background and connection gas”

Interestingly, once again these intersections only show up as “gas shows” on the charts, but are at least flagged for production…and as the results of log analysis suggested; they were not able to be fully assessed due to washout problems.

We did however find out porosities in these upper zones range from 5-10%...production comes from abut 6% at both Aneth and Lisbon…and from less with fraccing.

Moving ahead to the next key announcement…” Significant gas interval located over 30’ in Pinkerton Trail Formation”

A significant gas show, with levels up to 800 to 1,000 units, was intersected in the Pinkerton Trail over a 30 foot (9m) interval from 15,292’ to 15,322’ (4,661m - 4,670m). Background gas has since increased to 800 units.”

Once again, a decent clue to the significance of the current Leadville results showing 300 unit background gas and 600 units trip gas…AND INCREASING!

But what to make of all this?

Well…I have a feeling that with increasing depth, the mud weights are becoming significantly higher…after all, we now have some 4.6km of heavy mud “head pressure” bearing down on the formations(hard to imagine these sorts of pressures really)…and as a result, even significantly high-pressured gas zones will record lower background and indeed trip gas readings than might otherwise be the case higher up, due to the significant pressures on the formations. I would appreciate if any industry types could confirm my views on the mechanics here?

It is my view as an amateur (underline this word), that they already have commercial gas in Leadville…but have not yet hit a suitably porous enough zone to result in significant gas influx to the well bore…and ultimately, gas in drilling muds returning to surface...to record an individually “significant gas interval” yet.

They may have a tight structure, without fractured or highly porous "sweet spots"...but still one likely of commercial production if produced accross the entire formation width?

We will need to await post-drill testing however.

At the end of the day, my view is we have a twin zone field here; a combination “Aneth” field in the top half and potential “Lisbon” field in the bottom half…with the Pinkerton Trail “bonus” zone thrown in to really make this a unique prospect. Each of these two zones will likely be smaller all-up than the comparative namesakes…but collectively, the “Golden Eagle Field” may well be very much comparable to these other major fields.

One final point…

The 30ft “Pinkerton Trail” significant gas zone is officially in the Pennsylvanian aged sequence, but given it falls well and truly within the fault controlled accumulation closures of the Mississippian (Leadville) formation, from a hydrocarbon success point of view, I am more inclined to actually view the Pinkerton Trail gas pay as the equivalent of the first real Mississippian (Leadville) zone!

At Lisbon, the top pay zone of the Leadville formation (the main producer) ranges from about 10-50ft thick…at 30ft, the Pinkerton Trail gas zone effectively equates to about half of what was initially hoped from Leadville!

lol...the market has what it wants...but simply doesn't know it!

Wod for the trees here folks…it’s all there if you look hard enough!


Cheers!