Saw this tonight
The Haynesville Shale is back.
Natural gas production in the dry gas shale play jumped in both 2017 and 2018.
The U.S. Energy Information Administration is projecting Haynesville gas production in May 2018 to reach 8.54 billion cubic feet per day (Bcf/d), up from April’s 8.33 Bcf/d. Production was roughly 6.00 Bcf/d in January 2017.
If the May projection is reached, that would be a 42.3% increase in Haynesville dry gas production in just the last 17 months, a feat that has been quietly achieved, Kallanish Energy reports.
The Haynesville is again one of the top shale gas plays in the U.S., behind only the Appalachian and Permian basins. The Haynesville Shale is producing roughly 13% of U.S. shale gas production, according to EIA.
The industry is interested
That production is comparable to the Haynesville production five years ago in the play that covers 9,000 square miles in western Louisiana, eastern Texas and southwestern Arkansas, where nearly 30 drilling companies are at work.
There are strong signs the industry is again interested in the Haynesville. The Haynesville rig count has jumped from 16 in April 2016, to 39 a year ago, to 54 as of May 11.
Chesapeake a big Haynesville player
Houston-based Tellurian has reportedly had discussions with Chesapeake Energy, one of the biggest players in the Haynesville Shale. Tellurian is interested in acquiring Haynesville gas assets for its planned Driftwood liquefied natural gas export facility at Lake Charles, La.
Chesapeake gets 25% of its natural gas production from the Haynesville, 833 million cubic feet per day (MMcf/d), or 139,000 barrels of oil-equivalent per day (BOE/d), the Oklahoma-based company recently reported.
That production has jumped 22.1%, from 682 MMcf/d in Q1 2017.
It has three rigs at work in the Haynesville and expects to complete up to new 25 wells in full-year 2018.
A Chesapeake well in Louisiana’s DeSoto Parish is the top IP well in the Haynesville, producing 38.8 MMcf/d, according to media reports.
In 2017, Tokyo Gas acquired an interest in an E&P subsidiary of Castleton Commodities International that has significant acreage in the Haynesville. It was Tokyo Gas’ first equity investment in U.S. upstream assets.
Production in the Haynesville has jumped 25% from early 2016 to early 2018. That is more than the production increase of 20% in the same timeframe in the Marcellus Shale in Pennsylvania and West Virginia, according to EIA.
Doug Lawler, Chesapeake Energy CEO, told Forbes magazine in a March 2017 article the Haynesville was “largely written off by industry two to three years ago, but it has reemerged stronger than ever.”
The payouts on such wells are very attractive, at $3 per thousand cubic feet of gas, observers have said.
Reasons for increased Haynesville production
The latest production boost of Haynesville gas is due to increased drilling activity, longer laterals, more fracturing stages and improved completion techniques, plus private equity investment and growing demand for U.S. shale gas.
Additional rigs came in, beginning in late 2016, and the Haynesville also started producing higher per-well initial production rates. Drilling operators have gone to tighter stage spacing and significantly increased the quantity of proppant used per well.
The initial Haynesville wells with 5,000-foot laterals have grown to laterals measuring 7,500 feet to 10,000 feet and more in length. The result is stronger Haynesville well economics.
I saw this article in my twitter feed...sounds really good.
I suggest that you read Part Two of my blog, link follows:
Have a question. Lateral length seems to be one of the most critical components of the new well designs. Many of the the older units were formed around a much smaller lateral and still have wells to drill to complete the unit. What can be done to maximize these additional wells. Can the unit plat be amended to allow for these longer laterals?
Texas drilling units may be amended in size and shape. Louisiana drilling units do not have to be changed as the state allows Cross Unit Laterals, noted in the name as "HC". A lateral may transect as many units (governmental sections) as the operator has development rights.
Longer laterals are a big deal but tend to overshadow two facts in Louisiana. First, the Cross Unit Lateral wells eliminate the "no perf" zone in each unit effectively adding 80 acres of previously unstimulated rock. Second, high intensity completions make significant increases in all laterals regardless of length. Lateral length is important to the operator from a cost per mcf perspective but doesn't have any benefit for the royalty owner. The high intensity completion designs and additional stimulated rock are what improve production volumes within the unit and make for a better royalty check.
Thanks Skip. I am seeing in Nacogdoches County Bp, XTO, and recentlyAetheon permitting wells with stacked laterals. I am assuming these are Bossier on the top and Haynesville on the bottom. The only completion I have seen is the BP Pluto unit. It seems that this strategy if it proves effective should improve the economics of the Wells. The IP of the Pluto unit look pretty good to me.
Russell, I think the drilling of one Bossier well along with one Haynesville well in each unit as they are formed indicates an appraisal process. At least by BP and XTO. Those companies have the financial ability to not worry about rates of return on current wells. They are methodically HBP'ing large acreage positions that will see much more intense development in the next decade when natural gas is expected to bring a better price. One Haynesville well would serve to HBP the leasehold in the unit. There is no need to drill a Bossier well unless the company wishes to test the reservoir.
Are they completing both formations at the same time from the same wellbore - perhaps with one lateral for the Bossier and one for the Haynesville?
Not that I'm aware of. Ask Julie.
The stacked laterals are a regulatory construct, not dual laterals coming from the same well bore. Due to the complexity and pressures associated with the completion work, as well as costs, it does not currently appear to be practical to tap both formations from a single well bore.
Or dbob. Thanks dbob.