Posted on 04/06/2014 5:53:39 PM PDT by thackney
In January, 40% of natural gas production in North Dakota went to waste.
You read that right. 400 million cubic feet of natural gas was lit on fire and burnt. But that's peanuts compared to how much total natural gas goes to waste every year in the U.S.
And it's why I see natural gas prices being low this year...
Longtime Growth Stock Wire readers know about the U.S.'s booming oil production in shales like North Dakota's Bakken and Texas' Eagle Ford and Permian Basin.
Natural gas is a byproduct of oil production... And the shale plays are producing more natural gas than oil companies know what to do with.
As I told you last week, natural gas production is rising every year. According to the U.S. Energy Information Administration, natural gas production will grow 2.5% this year and another 1.1% in 2015. The overabundance of supply has kept prices low. And with natural gas prices so low, oil and gas companies have been slow to build the infrastructure to transport all the natural gas.
That's what happened in North Dakota earlier this year. There were too few pipes and not enough processing capacity. That's true in many parts of the U.S.
I remember visiting the Eagle Ford Shale in Texas in 2010 and seeing natural gas flares over practically every hill. "Flaring" is when wasted natural gas is safely burned off.
The table below shows the difference between the gross production and marketed production of natural gas in the U.S. That's the volume of gas produced from wells and the volume sold. After removing some other gases, the difference between the two is wasted natural gas. The final row shows the percentage of marketed production that was wasted.
As you can see, we wasted 3.8 trillion cubic feet of natural gas in 2013. That's 15% of the volume sold. At $4 per thousand cubic feet (MCF), that amounts to $15.2 billion wasted because pipelines don't exist to take it away.
This is the main reason I don't see natural gas prices remaining above $4 per MCF the rest of this year.
There is so much supply that we wasted over 10% of our production last year. This is supply that is already being produced. It could easily go right into pipes without drilling more wells.
Until infrastructure catches up to the overabundance of supply, low natural gas prices are here to say. That's why investors shouldn't bank on higher natural gas prices this year.
It is a shame though to waste it.
Yes it is.
I believe the chief reason for the glut in US natural gas is the lack of port facilities to export lng. We are constantly hearing that it will do no good to drill for our own oil, because energy is sold on the world market, and extracting more oil at home would have very little effect on the price we pay. At the same time, we are told that Europe cannot censure Putin for invading his neighbors, because Europe is dependent on Russian natural gas. ... at the same time we are told our natural gas is of little value because we have so much.
I don’t think I’m the one who is confused.
We do not have enough distribution capability. The pipelines are at full capacity.
Those are reason that keep prices lower, where the gas will be sold.
Agreed, generally, as to your mkt outlook. My broker (good man, but too much broker and too little analyst, if you get my drift) is a RAGING bull on natty. I hope his trades are long term, because the correct thing to do for the next 90 days or so is to write short-dated calls on rallies and short-dated puts on drops. Should be, statistically speaking, fairly easy money.
We shall see, as ever.
Best to you!
Here is my elementary understanding:
Current gas gathering capacity is constrained by:
- shale technology causing production to increase faster than expected;
- wells characterized by high initial oil (i.e. valuable) production, followed by steep declines;
- gathering pipe build-outs hindered by weather, easement and ROW negotiation, required federal approvals, setback requirements; and
- shortage of processing plants.
Capture, the inverse of “waste”, is increasing slowly. For example,the Bakken is 75% now, may increase to 85% in two years and 90% to 95% in six.
Meanwhile, oil and liquids are too valuable to defer production.
So, the article overstates the potential price impact of reduced flaring.
We have well head supply but because the pipelines are at capacity the purchase point supply cannot keep up with demand. Seems to me prices will rise b/c of that. And you can bet the d@mn dims won’t let us build anymore pipelines.
Your understanding is far better than mine. I’ll quit commenting on this thread as I am simply not knowledgable enough to do so. Hope you had a great weekend.
Indeed, I wouldn't be surprised if buses and taxis around the world are all switched to burning natural gas within the next 12-15 years.
The problem is collection capability. The cost to lay the pipe to each and every well to collect the small amount of gas each well is producing is exceptionally high. If and when it was collected it would then be transported and distributed.
Since these wells have a relatively short life and deplete quickly, the operator would probably never recoup the cost of laying the pipe.
The private sector leases and those on state land have a much better track record, and despite ever increasing production (as a byproduct of oil production), the percentage flared at the wellhead is below 30% and continuing to drop.
Why?
There are additional permits required to gain pipeline right of way permits on Federal and Tribal Land.
For those unfamiliar with the situation:
Oil is the product sought, worth approximately $100.00/BBL. Initial production on many wells is in the 700 to 1000 bbl per day range, with some much higher, and frequently with a similar number of MCF of (raw, unprocessed, wellhead) gas.
That raw wellhead gas contains not just Methane (AKA Natural Gas), but ethane, propane, butane (both normal butane and isobutane) and more complex hydrocarbons in gaseous form, as well as Carbon Dioxide and water vapor and other impurities. It must be processed to remove the heavier gases before the Methane fraction can be used as natural gas, and that includes liquefying the propane, butane fractions, and other heavier hydrocarbons and VOCs while removing solids, water, Carbon Dioxide, and other impurities.
IOW, what is being flared is not something you can just plug into and use with any reliable BTU output.
Why flare it?
Real-world logistics:
It cannot be stored, as produced, as yet there is no pipeline to carry it from the wellhead to the processing facility (in some places, no processing facility to send it to). So there is a construction backlog.
Economics:
While the cost of drilling a well is going down, it still takes between 7 and 10 million dollars to drill and complete a horizontal well with roughly 9500 ft. of lateral displacement at a vertical depth between 10,000 and 11,000 ft., (where most Bakken and Three Forks wells are).
During the initial months of production, the flow rate of the well is highest because the frac overpressure is bleeding off.
This higher, enhanced production period is the one where the oil company recovers much of, if not all of their initial investment in the well (and in so doing replenishes its drilling budget).
Consider that 1000 bbl oil per day=$100,000.00, 1000 MCF raw wellhead gas, is less than $5,000.00. Recovering the initial investment wins, the gas revenue not recovered is relatively minor in comparison to the oil revenue gained, and when the pipeline is connected to feed that production to the gas revenue will be a bonus.
Eight or more wells from the same pad have reduced the need for gathering infrastructure, and the wellheads and production equipment are grouped together.
This reduces the location footprint, meaning overall less earthwork, less construction cost, a single lease road instead of many, and a single feeder pipeline for a group of wells instead of one per well.
In combination with walking rigs, it also reduces the cost of rig moves, need for third-party rig movers, and the use of laydown machines for changing out drill strings for different phases of drilling--all of which translate to reduced cost (unless you are one of those service companies, then it may translate to reduced revenue).
Wells we drilled back in 2000 are still producing--these are not strictly shale gas wells, but are drilled in the strata which have inherent porosity which are generally composed of a mixture of interbedded dolomite, sandstone, siltstone, and/or limestone. Wells which are strictly shale plays may deplete more rapidly, but in the Bakken/Three Forks, the Shale is the source rock, adjacent strata are produced.
Follow-up frac jobs may yet liberate even more oil and gas when production declines. After 14 years of working these sort of wells we are still learning new tricks, even though the initial flurry of experimentation is pretty much over.
Although the dearth of pipelines and other needed infrastructure is deplorable, oilfield gas flares are not an indicator of the lack of storage or transportation facilities. Natural gas is found in, and is priced for market according to it’s btu concentrations. Most distribution utilities’ customers require a delivered burnablity of at least 950 but/cu ft. To achieve this rate, natural gas is blended from higher and lower powered gas sources, some as high as 1200 but/ cu ft.
However, if the gas found in a particular oil drilling site is too low of a concentration, say 550 but/ cu ft, it is unsuitable for blending because far too much expensive gas would be required to make the end product burnability acceptable.
The practice of flaring off weaker btu concentration gas has been a economic necessity in the industry for a very long time.
*BTU/ cu ft
They’d like to have that in the Ukraine right now....
Do you think that you will still be drilling in the Bakken formation 14 years from now?
The initial surge in activity was as much exploration (determining hotspots and limits in the overall play) as experimentation (finding out what works best), and to hold leases by production (single well on a 1280 acre spacing, as a rule).
Now we are going back and drilling additional Bakken and Three Forks wells in that same spacing.
Progress since we have started in production techniques including fracturing methods has improved extraction efficiency, and will likely continue to do so, so even wellbores which have been produced may end up being twinned.
There is ample room for over four times the number of wells already drilled, so even with increases in drilling efficiency I expect there is at least another 14 years left to finish the developmental drilling.
Put wellheads in virtually every square mile over more than 13000 square miles of North Dakota, and feeder pipelines are part of the problem. The number and size of gas processing facilities needed are beginning to catch up, but even those products need a way to get to market in an area where a very significant portion of the oil leaves by rail because there just isn't enough pipeline capacity.
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