Replies to This Discussion

Permalink Reply by Robert Duke on December 9, 2010 at 7:34

Hi Les,
Well, you know I keep a close eye on 13-8 and 12-8, as I have a well in that area that is not a barnburner, and am basically trying to figure out the prospect for improvement in the existing well as well as prospects for more wells and better wells in my section. So this new great well is 1 mile due north of 240963, which is a low producer (IP 3MMcf/d), 2 miles north and 1mile EAST of 240843 (my interest), which is optimistically a moderate producer (IP 8MMcf/d), and a bit further N (additional 1-2 mi) and and between 1 and 2 miles further EAST of two other low producers (240709, 241178, both around 3 MMcf/d). So is it possible that a lot of the problems in this area have to do with this "dip" issue you mention below? I presume it can also be porosity, other things affecting frac characteristics, shale thickness, etc., but here we now know there are great wells a couple of miles W and at least one great well as little as one mile N. So anyway, if it is "dip", is there a reasonable expectation that the operators will get better at staying in the paying shale?

Permalink Reply by Les Bamburg on December 9, 2010 at 7:46

Robert, I do not believe dip is a significant factor in the variation of well production rates in the area. Other factors such as formation quality, frac design & execution, etc are probably much more significant influences over the well performance. That is reason the wells in Section 4 and Section 32 will be key pieces of information.

By the way, this well is actually two miles north of the Anita Robinson 5 well (center lateral to center lateral).

Permalink Reply by Robert Duke on December 9, 2010 at 9:28

Hi Les,
Well, one more piece of data - the well in section 32 is in fact "in":
241167 HA RA SUA;WILEY HUNTER 32 H 001 E165 5955 41 00 032 13N 08W,
COMPLETED 10-25-10; GAS; HAYNESVILLE RA; 10,805 MCFD; 20/64 CHOKE; 1008 BWD; NO TUBING FP; 7692# CP; PERFS 13,112-16,935' MD
So this well is one mile due south of the well being discussed here:
EnCana, Wiley Hunter 29 #H1 Well, Serial #241086, S32(29)-T13N-R8W, Red River Parish, 21472 Mcfd, 25/64" Choke, 8347 psi Flowing Pressure

The "1 mile south" is center-lateral to center-lateral - but basically where one lateral ends the other begins (what - like 600 ft separation I expect). Note the 10.8 MMcf/d is on a significantly smaller choke than the 21.5 MMcf/d. Immediately south of it then is the Anita Robinson, at 3.4 MMcfd (240963), then 240843 at 8.4 MMcf/d, same choke as the 10.8 MMcf/d well.

I guess, as you say, we will know more with additional wells, and even more so, with a bit of production. Other wells near include 241313, 241352, 241397, probably just waiting final entries, and 241525 - spud entry 6/10, so who knows where it really is at. Anyway, I would have been more encouraged if this latest well was at 20 MMcf/d, but it is at the 20/64 choke, whereas the super well is at 25/64, similar CP, lots of initial water in this region everywhere...

Permalink Reply by Les Bamburg on December 9, 2010 at 9:55

Robert, the results of the Wiley Hunter 32 well essentially fits the trend of poorer well results as you move south from the Martin crossroads. Although the 10.8 MMcfd was on a smaller choke the flowing casing pressure was lower than the well in Section 29.

Also, there is the matter of higher initial water flow rates with these lower gas rates. All Haynesville Shale wells produce frac water initially but this is a sign of one of two possibilities. 1) Because the formation is not allowing for adequate fracture lengths, the frac fluid is being retained near wellbore and is flowing back quickly. 2) The Haynesville Shale formation (or adjacent formation) contains water that is being produced. I am inclined to believe the former is more likely.

Permalink Reply by Robert Duke on December 9, 2010 at 10:13

Interesting observation about "frac fluid is being retained near wellbore and is flowing back quickly" as a possible explanation; I can well believe that the shale characteristics are a bit different here, probably to an extent that the wells will not be fabulous producers. Would you care to hazzard any guess as to whether they will be economic within the next 5 or 10 years? My guess is that while this is not great news, the landowners in this area may make a bit of money, given a timeline of 5-10 years, but I am betting that you are in a better position to do informed guesswork (my other guess is that you are wisely unwilling to go out on a limb... ;-)). Thanks again for past and future insights, though! One mitigating factor - Liberty Field was unitized early, undoubtedly on pretty good terms for Encana, so this is pretty cheap leasehold for them; I will be curious to see if they extend permitting further into the SE units in the field; given the unitization timeline, they probably have until early 2012 to get more of the units in the field under HBP at very little cost (well, aside from the $9M holes...)

One more point (sorry for my usual multiple points). There was a discussion recently about one reason for Encana "gas factories", in addition to cutting infrastructure costs, was either the belief or observation that some shale can be more effectively fractured through simultaneous multiple laterals. Any opinions on that one? I am presuming these are all topics of some interest for folks "out of the core" but possibly still within a productive area.

Permalink Reply by Les Bamburg on December 9, 2010 at 11:40

Robert,

I would like to see some production history on the Liberty Field wells to get a better handle on decline and well EUR's. Then I can run the economic analysis based on that well production profile and my gas pricing outlook.

Yes EnCana was able to lease up most of their acreage in the Liberty Field area (and other areas) at low bonus rates. Personally, I do not believe they will drill any additional wells in the Liberty Field before any leases not already HBP expire. In fact many of such leases have already expired or will expire shortly and cannot be extended further without drilling.

The gas factories will not neccessarily increase well test rates but rather simply reduce costs thru fracture pumping efficiency. One example is the "zipper" frac where the operator alternates pumping frac stages between adjacent wells. Better fracture treatment design could potentially increase recoveries in the lower rate areas.

Permalink Reply by Micheal P. Loftin on December 9, 2010 at 10:42

Hey Les here is another one that looks like a good one in Martin, 241350 S08-T13N-R8w HA RA SUD;SUSTAINABLE FTS 8 H
COMPLETED 11-1-10; GAS; HAYNESVILLE RA; 21,672 MCFD; 24/64 CHOKE; 840 BWD; NO TUBING FP; 8844# CP; PERFS 13,688-17,545' MD.

Whats your thoughts?

Permalink Reply by Skip Peel - Mineral Consultant on December 9, 2010 at 11:16

The Martin Field is ground zero for the Haynesville Shale Play. Excerpt from A Chronology of the Early Haynesville Shale Play in NW. LA.:

The first Haynesville Shale well in the state of Louisiana was permitted January 12, 2006 by Encana Oil & Gas (USA) Inc. as a product type “00” (No Product Specified). It was drilled in Section 15 – Township 13N – Range 9W of Red River Parish in the Martin Field. The JUR RA SUA; ADCOCK INV LP ETAL was assigned serial #232697 (API Number 17081208570000). It spudded February 27, 2006 and drilled to a depth of 12,878’. On November 16, 2006 its status was reported as code 27 (Waiting On Orders). Encana converted the well to an “Observation Well” with status code 31 (Shut-In Dry Hole – Future Utility) on January 26, 2007. Since January 27, 2007, it’s last report date, it remains a code 27. From spud to final status report – 364 days. It has never been completed.

The Adcock Inv LP, #232697, is a code 31 - Shut-In Dry Hole, Future Utility. It was permitted and spud seven months before Chesapeake's SRLT, #234022 which many refer to as the "Discovery Well". IMO, Encana knew what they had in the Haynesville Shale and was quite willing to let Chesapeake take credit for discovering the HS. They didn't need to complete the Adcock Inv LP and issue a press release, they were already leasing in earnest.

Permalink Reply by Robert Duke on December 10, 2010 at 17:27

Skip, that is a great bit of history.  Any idea (as a landman) why there are 13 sections of land ununitized in that area?  I presume there are a few "challenges" in getting a unit tied down, but this just seems curious that this is where Encana made the break, and there is no drilling.  I am presuming that one factor was the recognition of the core off to the west, however that happened.

Permalink Reply by Skip Peel - Mineral Consultant on December 10, 2010 at 17:48

Robert, my best guess as to Encana's reason for choosing this section in the Martin Field for their initial HA test well would be S/N 176319 drilled in Section 14 in 1981.  I think that they looked at that electric log and liked what they saw in the Haynesville shale interval.  I can not tell you with any certainty why there are only 13 sections under HA Unit Order.

Permalink Reply by Les Bamburg on December 10, 2010 at 18:38

Robert, one point of interest is EnCana was actually pursuing the Bossier Shale rather than the Haynesville Shale when they first leased up the area.  Most of the leasing occurred well before the Adcock well was even drilled.

 

By the way, which township are you referencing for the 13 sections?

Permalink Reply by Robert Duke on December 10, 2010 at 20:07

Hi Les & Skip,

Thanks for the info.  I actually said "ununitized" - maybe my terminology is somehow off, but what I meant was there are 13 640 acre sections that are NOT HS units right around here, including section 15 itself, per the sonris GIS map.  They are all T13N-R9W I believe, the section runs are 7-9, 15-18, 19-21, 28-30.  There actually appears to be a well (241439) not in a unit in section 28, just completed on 10/15/10 with an IP of 25.6 MMcf/d and cp 9044#; man, another barnburner...  I just found it curious that they would not attempt to lease and exploit the sections in this area - the sections are to the immediate west, which I am presuming is hot core all the way over into Desoto (sonris just croaked, or I would get data on the wells immediately to the west, they are all in adjoining T13N-R10W, wells 238131, 238493, 241318 on the township border).

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