Don Briggs: Haynesville Shale play is far from over
Common thought is that the Haynesville Shale natural gas play is over. Pack up your trucks and move to another shale play. False.
Indeed, the Haynesville did see a mass exodus starting in early 2012 due to natural gas prices dropping to an historic low of $1.81. What can help the prices rebound?
The Haynesville Shale saw a rig count rise to 139 in 2010-2011. This was a direct result of having an abundant supply of dry natural gas in the ground, $12-$13 natural gas prices, and developing technologies to retrieve these resources.
As the exploration and production companies moved into the Haynesville Shale region, the natural gas market became inundated with supply. As the demand was much lower at the time to utilize the supply, the market experienced a great drop in price with the rig count following suit.
However, the Haynesville Shale play is far from over. Reports say that roughly 30 percent resources have been recovered from this particular play. While more than 2,500 wells have been drilled with more than 2,200 of those producing dry natural gas, the price must continue to tick upward in order to see rigs return to the Northwest Louisiana area. Since 2012, the market has now moved in a positive direction, as natural gas prices are now well over $4 and the Haynesville rig count is hovering in the 20s.
Three functions of the market will bring natural gas prices back up to a stable place:
• First, the current manufacturing renaissance in Louisiana will be a needle mover for the natural gas industry. The petro-chemical industry operates on natural gas as a baker does with flour. Over the next five years, the manufacturing industry will be demanding nearly four times the amount of natural gas a day that the largest producer in the Haynesville Shale was extracting a day in 2011.
• The second market driver of natural gas usage is power generation. In July 2012, for the first time in United States history, natural gas surpassed coal as the chief power generator. Over the next several years, many older coal and nuclear plants are being taken off line and replaced by natural gas.
• The third contributor to natural gas demand is the exporting of liquefied natural gas around the globe by companies such as Cheniere Energy from their facility in Cameron Parish. Cheniere will have the capability to ship LNG by tanker to the Asian and European markets where natural gas trades at nearly four times the price of the United States market.
It was just six short years ago that the U.S. had a shortage of natural gas. Nearly 50 import facilities were being constructed to bring in natural gas, whereas today, over a dozen facilities are in the federal approval process to construct additional LNG export locations.
While weather might drive up the price of natural gas, this is temporary. Sustainable natural gas prices higher than $5 will bring back that encouraging site of rigs towering across our rural and urban horizons in Northwest Louisiana.
Don Briggs is president of the Louisiana Oil and Gas Association.
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Replies to This Discussion
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Permalink Reply by little ole 1st grade teacher on
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What about East Texa/Shelby County, Texas?
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Permalink Reply by Keith Mauck (Site Publisher) on
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30% recovered seems like a high number, any thoughts on what reports he is drawing that figure from?
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Permalink Reply by Skip Peel - Mineral Consultant on -
The percentage of locations drilled (recovered) depends on your assessment of the extent of the Play. If Mr. Briggs is referring to Core and Tier One acreage, which I suspect he is, his 30% may be accurate if a little high. If Tier Two acreage was included the percent would be less than 20%. There's just no way to know when NG prices will be high enough to make drilling Tier Two economic.
Generally speaking Core acreage has per well EURs above 8 bcf with some being above 10. Tier One acreage has EUR of 6 to 8 bcf. Tier Two acreage is 4 to 6 bcf. It is yet unclear how the drilling of Cross Unit Lateral wells may change this dynamic. Someday the cost to produce an mcf will come down enough and the price of NG will go up enough to make Tier 2 worth drilling but I have no crystal ball that can predict when that will be.
little ole 1st. grade teacher, the data that Mr. Briggs and I are using is from Louisiana. The Texas Railroad Commission doesn't provide enough easily accessible data to form an opinion for the Texas portion of the Haynesville Shale Basin.
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Permalink Reply by Larry G Smith P.E. on
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It is my understanding that when a well is fracts, the "tube" that formed around the drilled/cased hole is approximately 200 to 300 feet in diameter. The pressure used in this process is very high pressure. That will comes in at high pressure for about a year and a few month, with large volumes of gas reported. Then in the short time, that frac pressure is drawn down and then the well starts producing less. On a 640 acre tract, the first well is drilled along either the west or the east boundry of that tract/section. When these wells were first hitting the market, the production and amount of gas that was being estimated was on false production rates, that was on frac production, not on actual production from the formation. From what I see in that area, most sections have only one well drilled in that section (640 acres), that means that a very small portion of gas has been removed from that section. I have been told that up to 10 wells could be drilled in one of those sections. I would guess that this would hold true for all of the Shale Gas Formations.
I have seen this happening on a small trac of land that I own in DeSota Parish. The first companies that drilled that area were not being truthful with estimates of this area. Bankers and investors were not explained all of the facts in Horizontal Frac Production. My take.
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Permalink Reply by Skip Peel - Mineral Consultant on
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The frac cylinder is in that diameter range but the frac operation does not introduce increased pressure to the formation on a long term basis. Upon flowback the formation reverts to its pre-frac pressure. The reason for the high early production is the artificial fractures connecting greater formation surface area directly to the wellbore and the naturally high, over-pressure in the formation pre-existing prior to fracture stimulation. The decline in formation pressure and the production over time from the major fractures account for the steep decline curve. Instead of down spacing (more wells per unit) the trend seems to be going in the opposite direction led most noticeably by EXCO. Communication between laterals has caused EXCO to increase spacing and reduce the number of wells per unit.
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Permalink Reply by Larry G Smith P.E. on
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Skip, what pressure do they use to open up that tube area? That formation on its own, really does not have much pressure. What pressure would that bore hole have if they only preforated the Casing and allow that well to produce? I look at the well pressure today, flow pressure around 950 # and when it came on line, around 6500# with a steady drop in pressure over three years. With the Choke at 17/64th starting off and now down to 14/64 th to maintain or hold back a little on the pressure and production.
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Permalink Reply by Skip Peel - Mineral Consultant on
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One of the very first comments made and emphasized upon announcement of the Haynesville Shale Play in April, 2008 was that the formation was "over-pressured". Pumping pressures vary by locale according to brittleness. No need to frac out of the target zone. If you look at the Well Scout portion of a SONRIS Lite Well File you will see the original formation pressure for each well. 6500# is on the low end of the range. The best wells have formation pressures in the 8000 to 10000# range. Typically choke settings are increased over time as formation pressure drops.
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Permalink Reply by Larry G Smith P.E. on
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I would think that the lower pressures were due to less pressure used in the frac process, while the higher pressures are due to a tighter formation and higher pressure used to frac that formation. The formation pressure is only measured when the well is completed and is first opened up. There is no way to measure the formation pressure until the well is fraced and completed with the tree in place.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Formation pressure varies by location owing to depth and GIP. Maybe someone can explain it better than I. You might want to ask Jay. Choke settings are difficult to unravel as the capacity of a given gathering system is finite and the number of wells and flow rate for each has a lot to do with the setting for each individual well.
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Permalink Reply by Larry G Smith P.E. on
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The Hainsville formation is a very tight formation, that is why they have to frac the formation to allow it to produce gas. If you just drill a straight hole in to that formaion, there would be very little to no production. From what I have seen on the well depth through out the Hainsville area, the verticle depth is very near the same from north to south, range in the 12,500 ft area plus or minus a few 100 feet.
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Permalink Reply by dbob on
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Larry
The wetter gas pursued by Anadarko is getting produced in the 10,000 foot depth range. areas to the south and west get deeper and hotter, approaching the 12,500 mark.
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Permalink Reply by Skip Peel - Mineral Consultant on
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HA TVD is generally 10,000' in north to >13,000' in the south-southwest..
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