The following is an excerpt from a recent presentation by a major Marcellus Shale operator. I researched the CHK Haynesville Shale well with the most recent well cost entered in SONRIS for a comparison and I suspect that CHK's well designs and costs are similar to Vine O&G, the other most active driller currently. The differences are stark and unlikely to change over the near term. As more Marcellus gas finds its way to the Gulf Coast market I suspect it will cap the price of natural gas from Texas and Louisiana production. The other side of the coin, the more optimistic one, is that demand will be increasing for LNG liquefaction and export by NG pipeline to Mexico.
In the SW PA "dry" Marcellus area, a five well pad brought on line in April is expected to have an EUR of ~22 Bcf per well (3.0+ Bcf per 1,000 lateral feet) at a cost of ~ $5.3 million. ___ plans to bring on line 49 wells in SW PA "dry" area (~7000 ft. lateral, $5.2 million well cost, 17.6 Bcfe EUR ....
In the SW PA "wet" Marcellus area, a four well pad brought on line at end of 2015 is expected to have an EUR of ~28 Bcfe per well (4.0 Bcfe per 1,000 lateral feet). ___ plans to bring on line 31 wells in SW PA "wet" area (~6,970 ft. lateral, $5.8 million well cost, 20.6 Bcfe EUR ....
In the "super rich" Marcellus area of SW PA, two pads with a total of 10 wells brought on line in Q1 are expected to have an EUR of ~14 Bcfe per well (2.8 Bcfe per 1,000 lateral feet) with a cost of ~$4.8 million. ___ plans to bring on line 13 wells in SW PA "super-rich" area (~6,660 ft. lateral, $5.9 million well cost, 16.0 Bcfe EUR ....
CHK S/N 248904, Completed 7/11/15 (most recent completion with well cost entered in SONRIS)
14.03 MMCFD, 5280' Perforated Lateral, 14 stages, $8,073,396.
Although there are no EURs available for this well, the better Haynesville Shale horizontal wells are likely in the range of 7 to 10 Bcf or, at a very optimistic comparison, about one half the better Marcellus well production at about twice the cost ($5.8M/6,970' = $832 per foot of perforated lateral vs. $8.0M/5280' = $1515 pfpl).
Shale drillers produce more gas with less wells in 2015
By Susan Phillips August 1, 2016 | 3:37 PM stateimpact.npr.org
Natural gas production in Pennsylvania is up despite a drop in the number of new wells. The Department of Environmental Protection released its 2015 annual oil and gas report on Monday, detailing such things as the number of wells drilled, locations, and inspections. The state’s shale wells produced 4.6 trillion cubic feet of natural gas in 2015, marking a continued increase since the start of the shale gas boom. This happened despite a drop in newly drilled wells. In 2015, shale producers drilled 785 wells, about half the number developed in 2014, which was 1,372.
The top three producers included Chesapeake Energy, Cabot Oil and Gas, and Range Resources. The top counties for shale gas production include Washington, Susquehanna and Greene counties.
The report also detailed the drilling activity for the Utica and Point Pleasant Shale Plays, which the DEP says could expand should the market for shale gas improve. Both of those formations lie beneath the Marcellus, and just 55 wells were drilled into those formations in 2015.
DEP also reports that while both conventional and unconventional well inspections have increased since 2008, the number of violations has decreased. For shale gas wells, 404 violations were issued by inspectors in 2015, compared to 1,280 in 2010. The number of conventional natural gas well violations more than double the number for shale gas wells, this despite far more unconventional than conventional wells.
The gas industry paid far less in fines during 2015. After reaching a peak of $7.1 million charged to drillers in 2014 at the end of the Corbett Administration, DEP issued a total of $3.4 million in sanctions in 2015. DEP investigations into water contamination through methane migration, yielded no findings of wrongdoing by the gas industry last year.
Industry and environmentalists reacted differently to the findings. The Marcellus Shale Coalition released a statement praising the collaborative efforts of regulators and producers.
“At the same time, while DEP’s performed a record number of inspections, overall regulatory compliance is at a five-year high and trending in the right direction,” said MSC president Dave Spigelmyer. “We’re also very proud that despite the Commonwealth’s unique geology and longstanding shallow methane-related challenges, there were zero stray gas issues in 2015, thanks in large part to the strong, common sense well construction regulations that our industry supported.”
Spigelmyer added that any new taxes could jeopardize that progress.
Maya Van Rossum, from the Delaware Riverkeeper Network, said the numbers don’t paint the real picture.
“The level of harm being inflicted by drilling and fracking on our communities and environment is not going down it is continuing to grow,” said Van Rossum. “You still see deforestation, you still see methane emissions, you still see the opportunity cost in that we continue to drill and frack instead of investing all that time and energy and resources into the clean energy path.”
Doob and HBP: Would you buy 22-24 Bcf per well by CHK in the Haynesville? I would agree that companies put the best spin possible on their press releases and presentations however anything beyond that assessment would invite investor lawsuits and/or questions from the SEC. If you're not keeping up with the impressive increase in IP and EUR in the newest well designs in all major basins you will continue to find these reports hard to believe. The following is from the Aug. 4 CHK presentation. I have added links to both the CA 12&13 - 15 - 15 wells for reference. The disparity between the IP in the state test and the IP reported by CHK is due to the extended length of time these long lateral wells take to "clean up".
Transformational change in Haynesville Shale economics and well productivity
˃Extended laterals and optimized completions significantly enhance economics across the field
CA 1 3,000#/ft. 10,000' Lateral $9.8MM 38 MMcfd 22 - 24 Bcf EUR
I do not believe the press releases because they have been exceedingly optimistic in the past and because they are not supported by data. Remember the Kardell well in San Augustine TX operated by Crimson? It tested at "30.7 million cubic feet of natural gas per day on a 37/64 inch choke with 6,824 psi of flowing pressure". It has produced 1.08 BCF in the six plus years since.
I have good assets in the Haynesville, and believe me I wish the fairy dust was real--but it is not.
The Kardell was a great well that Devon pulled too hard as evidenced by the 37/64 choke. They, and other operators, learned their lesson. If you wish to make your point you need to pick another well. I believe the IP announcements are factual. The EUR (estimated ultimate recovery) is just that, an estimate. however there are rules on how companies derive that figure because total reserves are a key metric used in financial transactions. The SEC is watching.
That's the story--and it's valid, but it doesn't explain how a 2 BCF well can become a 20 BCF by doubling the length, increasing the frack etc. Because this post got me curious I just downloaded all the Haynesville production in San Augustine. The graph is attached here. the 50th percentile well is just over 2 BCF. 18 wells out of more than 1000 have made more than 7 BCF. About 100 (10%) might make more than 5 BCF in 15 years of production. The stats aren't much different in LA.
Nice work, Doob. It has become evident just how poor the recovery factor was in the early short lateral wells. The difference in 1.0 well designs/performance and 3.0 are significant. Using 1000 wells with likely ~900 representing 1.0/2.0 does not disprove the performance of 3.0. The data points are much fewer but try completions since June 2015 and see how that graph looks.