"THE HAYNESVILLE SHALE SIZZLES WHILE THE BARNETT COOLS"
The discussion title is from an article by Arthur Berman who is Contributing Editor for "WorldOil.com - The oilfield information source". A link to his article is contained in his response to our discussion on decline curves. I have excerpted his post to begin this discussion as I think his professional views are most informative and should be of interest to our members. Mr. Berman has granted me his permission to repost his comments. Thank you, Arthur.
Reply by Arthur Berman 3 hours ago
Skip,
All shales are not equal. The Haynesville Shale is overpressured and, therefore, less brittle than the Barnett, so fracture stimulation is not as effective. It is also much deeper, so there are more problems reaching sufficient pressure with pumps, etc. to create a good fracture stimulation. Also because it is deeper, any fracture that is created is less likely to remain open.
For a fuller discussion of Haynesville vs. Barnett, see my September column in World Oil: http://worldoil.com/magazine/MAGAZINE_DETAIL.asp?ART_ID=3640&MO... .
The flatter "tail" of the decline curve is not something that I see much value in, since it is highly interpretive at this early stage in Haynesville production history. Also, monthly production volumes in the flat portions of hyperboloic decline curves rarely generate enough revenue to cover lease operating expenses, so much of the reserves from this phase of a decline curve are not commercial, though technically recoverable.
When I do a decline analysis, I usually figure something like $5,000-10,000 month are necessary for lease operating cost. Assuming that current gas prices are $7.00/Mcf and about $1.00/Mcf of that goes for midstream costs, and another $1.00 or more goes to pay G&A costs, that means that the economic limit of a well is between 1-2 MMcf/month. That doesn't include taxes and royalty which is perhaps another $2.00/Mcf, so really the economic limit of a well is 1.75-3 MMcf/month.
All the best,
AEB
Reply by Arthur Berman 3 hours ago
Skip,
All shales are not equal. The Haynesville Shale is overpressured and, therefore, less brittle than the Barnett, so fracture stimulation is not as effective. It is also much deeper, so there are more problems reaching sufficient pressure with pumps, etc. to create a good fracture stimulation. Also because it is deeper, any fracture that is created is less likely to remain open.
For a fuller discussion of Haynesville vs. Barnett, see my September column in World Oil: http://worldoil.com/magazine/MAGAZINE_DETAIL.asp?ART_ID=3640&MO... .
The flatter "tail" of the decline curve is not something that I see much value in, since it is highly interpretive at this early stage in Haynesville production history. Also, monthly production volumes in the flat portions of hyperboloic decline curves rarely generate enough revenue to cover lease operating expenses, so much of the reserves from this phase of a decline curve are not commercial, though technically recoverable.
When I do a decline analysis, I usually figure something like $5,000-10,000 month are necessary for lease operating cost. Assuming that current gas prices are $7.00/Mcf and about $1.00/Mcf of that goes for midstream costs, and another $1.00 or more goes to pay G&A costs, that means that the economic limit of a well is between 1-2 MMcf/month. That doesn't include taxes and royalty which is perhaps another $2.00/Mcf, so really the economic limit of a well is 1.75-3 MMcf/month.
All the best,
AEB
Views: 104
Replies to This Discussion
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Permalink Reply by Skip Peel - Mineral Consultant on
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Hello, Gray. I suspect that we may wait awhile for replies from Mr. Berman as I suspect he is unable to follow the site as closely as you and I. A good question for our site experts might be, "what are the reservoir differences or variations between the geological formations that you mention"? The varying names for the formations can be confusing. Especially when there are "sands" with the same names. I suspect that the shale in both states, whatever the names, relate to Arthur's analysis in large part on depth and therefor formation pressure.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Arthur. Your statement that, "monthly production volumes in the flat portion of hyperbolic decline curves rarely generate enough revenue to cover lease operating cost" leads me to ask whether producers will continue to operate a well once it is no longer "commercial"? If CHK's recent report is accurate, an 81% decline in the first year of production from a well with initial production of 10MMCFD (CHK's average for its first 16 horizontal wells) would seem to indicate that production will enter the noncommercial range in the second year of production. In previous discussions, members, myself included, have speculated that the productive (commercial) life of a natural gas well was 15 to 30 years.
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Permalink Reply by ALongview on -
I thought it said 1.75-3 mmcf/MONTH not 1.75-3 mmcfd? This seems like it would make a difference in when the well would become noncommercial. By the way I am no expert and didn't stay at a Holiday Inn Express last night, I am just trying to understand the technical info so please be nice if I am way off base.
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Permalink Reply by Skip Peel - Mineral Consultant on
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ALongview, you are not off base at all, regardless of your choice in motel accommodations. My error. Thank you for the correction. I'll have to run some new figures now to try and determine when that production level would be reached under the announced parameters. Should make more sense.
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Permalink Reply by Skip Peel - Mineral Consultant on
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ALongview. I will try again. Please check my figures to see if I am correct.
10 MMCFD X .19 = 1.9 MMCFD in Yr. 2
1.9 MMCFD X .66 = 1.25 MMCFD in Yr. 3
1.25 MMCFD X .78 = 975 MCFD in Yr. 4
975 MCFD X .83 = 809 MCFD in Yr. 5
809 MCFD X .87 = 704 MCFD in Yr. 6
704 MCFD X .89 = 627 MCFD in Yr. 7
627 MCFD X .91 = 570 MCFD in Yr. 8
Of course, Mr. Berman's threshold for production reaching a point of "noncomercial" operation is based on $7 MCFD. A fair figure for an example at the present time. I will not ask him to speculate on the price of ng going forward as no one can predict such. I'll let any interested members run their own numbers. I will try to do some additional modeling when I can find time. At present, I just wish to present a viable model of production decline for discussion amongst the members. I hope that I got it right this time. Thanks.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Conversion Note: 1.75 MMcf/month = ~58 Mcf/day
3.0 MMcf/month = ~100 Mcf/day
When I have the time, I will try to run the numbers out in an attempt to estimate the years of commercial production for the example well.
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Permalink Reply by ALongview on
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This looks great and I will be anxious to see any further models. Much better than a two year well. Thanks again.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Yes, Much Better. Thanks for busting me. Obviously the difference will be a tremendous increase in the commercial years of production. And with a probable increase in the future price of ng, the 2 to 3 decade productive well life estimate may just be accurate.
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Permalink Reply by Lerret on
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I trust Berman's decline analysis from what I see in the Fayetteville Shale. The declines in many wells are expotental and after 3 years, many wells are still in free fall. Where/when the decline starts curving is more important than what the initial rates are but if you don't recoup a lot of the investment in 18 months, you may never recoup it.
If CHK's recent report is accurate, an 81% decline in the first year of production from a well with initial production of 10MMCFD (CHK's average for its first 16 horizontal wells) would seem to indicate that production will enter the noncommercial range in the second year of production.
300 MCF/Mo will payout rather quickly even at steep declines, but the question remains will the curve flatten (turn the corner) in hyperbolic decline and when. A straight line plunge is not a good thing.
The problem with all the shale plays is that once the gas drilling stops, the whole field will decline precipitously. After 18 months you would expect production to fall by 75% in most plays.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Thanks, Lerret. I am still processing your input and Arthur's. Decline curve analysis to a topic of great interest to me and I have been waiting for some reasonably reliable data to initiate this discussion. I am a little overwhelmed with the jest of the professional analysis. I see numerous older vertical wells producing from formations other than the HS that have been productive, and I assume commercially so, for 25 or more years. The steep decline in initial HS production and the question of projected ultimate commercial well life should be of great interest to those lucky enough to have royalty income in their future. I hope that my curiosity on the topic may be of benefit to them. Your analysis is much appreciated. Skip
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Permalink Reply by Skip Peel - Mineral Consultant on
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It appears to me from my layman's calculations, already exposed to be sometimes off base, that a HS horizontal well based on the averages used in the previous computations MAY reach nonprofitable production levels in years 7 through 9 not withstanding the potential for the increase in the price of a mcfd of natural gas in future years. As a gross example, is this correct?
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