Skip to comments.PN Bakken: NDís gas woes
Posted on 12/05/2012 6:12:46 AM PST by thackney
Finding a solution to North Dakotas ballooning gas-flaring problem will require a very difficult balancing act that could take until the end of the decade to work out.
We have to balance the ability to build gathering systems against the waste that takes place with flaring, Lynn Helms, director of the states Department of Mineral Resources, said in a Nov. 20 Webcast.
So were looking at toward the end of this decade before we really get this flaring dynamic under control.
Gas production continues to increase at a faster rate than the more desirable crude oil, setting yet another production record in September at 793,546 thousand cubic feet, mcf, per day. Average oil output for the month was 728,494 barrels per day, also a record.
Bakkens mounting gas volumes
By the time oil production reaches 1 million barrels per day, projected to occur in 2013 or 2014, the associated gas will amount to around 2 billion cubic feet per day, a huge volume that has state regulators concerned. If we are flaring 5-to 10 percent of that, thats going to be equal to all the gas we produced in the first five years of the 21st Century, Helms noted.
Additions to pipeline gathering and processing capacity are said to be helping, but the percentage of gas flared rose to 30 percent in October. In comparison, oil companies flared 23.5 percent of their natural gas in December 2010, up from 13.7 percent the year before. The historical high was 36 percent in September 2011.
Even though were seeing a lot of build out of infrastructure we are still very much in a struggle to reduce flaring in the state, Helms said. This is going to be a hard problem to solve.
Flaring exemptions on rise
However, because of the relative slowness in expanding the gas-gathering and processing system, he added, the state is getting a tremendous number of operator requests for variances and exemptions from regulations governing flaring. Drillers can now flare natural gas for one year without paying taxes or royalties. After one year, companies must either connect to a gathering line, an electrical generator, or apply for an exemption. The exemption would allow an operator to not pay taxes and royalties should connection or an electrical generator be deemed economically infeasible.
Helms said that strict adherence to North Dakotas production restrictions in the current infrastructure environment could potentially reduce the profit on Bakken-Three Forks wells by 25 percent.
For investors thats probably too severe and would very (likely) reduce the economics and impact the number of people that we have working, the rig count, and all those sorts of things, he said. At the same time, we have to look at the waste issue, Helms said.
Oil outweighs gas
However, the economic reality is that gas makes up just 6 percent of the energy and a paltry 3 percent of the income derived from Bakken-Three Forks production, while the more desirable oil makes up well over 90 percent of the pie. Were seeking that balance the difficulty in building up the gathering systems and getting easements against the economic waste, against the resource waste and energy waste, against having a severe economic impact, Helms explained.
He said for now, the state has opted to allow more flaring because strict application of the regulation would negatively impact the profit of the Bakken well by as much as 25 percent in an environment where they (operators) cant get a gathering system.
The oil and gas industry is reportedly investing more than $3 billion in infrastructure to capture the natural gas.
Most land in private ownership
Helms said the biggest problem in expanding the gathering system is acquiring rights of way or easements across private property to lay pipelines. In North Dakota, 82 percent of the land is privately owned, he said. Its a long process of a half-dozen right-of-way negotiators coming to a house and asking for more and more and more of their land, he said.
Thats because todays agreements generally call for one pipeline per exclusive easement, so they begin to take up a lot of their land, Helms noted, adding that lawmakers are looking at possibly replacing the current practice with multiple use corridors, where several pipelines and a power line would occupy the same easement.
Flared gas alternatives
The state has looked at a number of possible uses for the gas that is currently being flared, including the conversion to anhydrous ammonia fertilizer. (See related story, page 13) Previously investments were made for research into electrical generation, and compression of natural gas for use as fuel or transport to a processing facility.
Future projects may include use of flared gas to produce petrochemicals, conversion of flared gas to liquid fuels, and removal of natural gas liquids from flared gas.
It is hoped the legislature will consider tax exemptions and royalty certainty to provide incentives for beneficial uses like the above, Helms said in his monthly Directors Cut report.
Sounds like the EPA has received their means of shutting them down on a silver platter.
My thoughts exactly, just the excuse Obuma needs.
Anyone who can design a small plant that can operate at a profit, is modular (think 40 ft. container sized loads), and can take advantage of the gas, making fertilizer, generating electricity, and possibly separating NGLs has the potential to make a lot of money. Consider, too, the development shift in the Bakken/Three Forks is toward pad wells, with 4 to 8 wells drilled from the same location, which will mean that the gas involved won't be from just one well, but as many as four (or even eight, as some plans call for).
>> Future projects may include use of flared gas to produce petrochemicals
Fertilizer prices are too high. Utilizing otherwise wasted natural gas as feedstock would seem to be a win-win.
I’d like to see that happen closer to home (central TX). I don’t think we’re flaring away a *whole* lot in my area though.
Although if there ever IS a real issue with man-made global warming, I suppose 30,000 gas flares going 24/7 would do it.
This is a valuable resource and should not be wasted in that manner.
Is this the kind of the thing the planned refinery that Bobby Jindahl is looking to build in Lousiana would eliminate? I though I read something inthat thread. The flaring seems like such a waste of potentially usable product.
Thackney we’re running into the same problem here, with all the local drilling we don’t have the gathering system in place to bring it all in and we’re having to flare it. Building the pipelines is alot slower than the drilling.
That is the design used on the Alaskan North Slope.
So where did you get your engineering degree?
If you know how to avoid this, you could make millions!
You obviously know more than the engineers involved. Why aren't you hopping on this?
When you have no where to go with it you have to flare it until you do.
No. A refinery does not affect this.
The flaring is being done due to a lack of natural gas gathering line piping being in place. It will get built but it takes time; drilling is faster.
Maybe that explains part of the push for a carbon tax.
But not really. The wells are spread apart by virtue of the lease spacing (two square miles), so the effects of any flare combustion products are significantly diluted.
The Bakken oil (and gas) is sweet, too, and the absence of significant amounts of sulfur will make action against flaring more difficult.
ANY extra heat in North Dakota is welcome this time of year. (8^D)
We've had snow on the ground for over a month, and temps range from single digits at night to sometimes the low 30s in the heat of the day (it is only "Fall", not "Winter", yet).
Not sure what the weather is like where you are.
(One of the few places on the planet with people and worse weather!)
It just makes sense, imho. Smaller footprint, more centralized production facility, one location, one road, etc. It saves a fortune in infrastructure costs, and resources as well.
Red is the pad, disturbed area.
Lines are the well bores, circles the end of the bore.
It is even more impressive seen in 3D as it follows a narrow layer.
Of course we could build a pipeline instead . . .
Now we know why they're against that, too.
Since when does logic have anything to do with what the EPA/enviro-Marxists do?
Somebody IS hopping on this, and they are going to get very, very rich.
No I am not an engineer, but I do business in the Oil Patch.
I know this is an issue that concerns them and they are working on it very diligently.
Now please state your argument why burning off millions off cubic feet of natural gas every day for no good purpose is a GOOD idea.
I never said it was a good idea. Right now it is a necessary side-effect of producing oil. Are you suggesting they stop drilling for oil until a pipeline is built or your genius friends present their secret solution?
Thank you for those explanations. I learn something every day...and fellow Freepers are a goodly part of that. :-)
This is North Dakota. We can use all the heat we can get. (8^D)
It isn't burned off for "no good purpose", it comes out of the ground with (dissolved in) the oil. The oil goes into big tanks (450 bbl uprights) neatly. The gas, not so. Without a way to contain, process, or transport the raw gas, you burn it, otherwise you risk explosions, nasty V.O.C.s and all sorts of other problems.
The alternative is to stop production and bring one of the few bright spots in economic gloom to a screeching halt until a feeder pipeline can be built over hill and dale to every wellsite.
I know North Dakota is only that big on the map, but you are talking about roughly 20,000 square miles that will have to be covered. That takes time.
The situation is temporary for any given wellsite, the amount being burned represents the lag in building pipelines to transport the gas.
What is the horizontal scale?
Do you have a link for this?
Seismic is good (when you have it), but we often end up steering (up/down) by MWD Gamma Ray tool readouts and cuttings samples. For "layer cake" geology, there are a lot of ups and downs down there, and the occasional fault.
Can you explain why you think burning at the well site is significantly worse for the environment than burning at the end user heater or power plant?
That is CD-2, the western drillpad from Alpine by ConocoPhillips, located:
The image I posted was from a blog.
http://northslopeoil.wordpress.com/ See March 1, 2011
It was taken from a bigger map of essentially the entire North Slope shown that way. I know I’ve seen that before at one of the smaller oil company web site. I’ll find it and link to it to show scale.
This is the same area, larger map with a scale included.
The most western cluster on the link above is the same well pad, just to the left of the words Alpine 1 (which is the cluster to the right). This link doesn’t have the detail of the curving bore path, but it does show stop and start point and it includes a scale. Several miles long on most of the well bores.
I used to work this area. I was a design engineer for the facilityies North and South which came a few years after the CD-2.
One more link for a reference map in relationship to the rest of the North Slope fields.
“Anyone who can design a small plant that can operate at a profit, is modular (think 40 ft. container sized loads), and can take advantage of the gas... generating electricity...has the potential to make a lot of money.”
We have three German made generating plants in 40’ containers sitting at the landfill four miles south of my house, burning landfill methane and generating kilowatts.
Correct. Texas already has a large infrastructure of pipelines, thus not a problem.
Thanks for the info. I’ll see what I can find out about the manufacturer, and what the requirements are for preprocessing the feedstocks.
“Can you explain why you think burning at the well site is significantly worse for the environment than burning at the end user heater or power plant?”
Hey, stop thinking outside the box.
Looks like a printed circuit board.
Spider Flares ...
The one problem with power stations is this: You have to have the infrastructure to handle the power transmission. Again, that's a lot of power line either laid or strung in a state where that infrastructure is pretty spread out. There is a question of putting lines on poles where they will be exposed to extreme winds and intense weather (especially in winter), but the cables remain recoverable later when the wells have depleted or the feeder pipeline is laid, versus burying lines where they will be difficult to recover, more expensive to obtain right-of-way, but protected from the elements. (A blizzard two years ago took out the 5 major trunk lines coming into the NW corner of the state, cutting power to 6000 square miles--poles did not fare well in many areas, winds were in excess of 70 MPH.)
The alternative is to develop a mini gas plant to either separate out the Natural Gas Liquids (propane, butane, ethane, and heavier NGLs), and flare any excess. The liquids could be stored onsite and hauled out by truck.
--As could Anhydrous Ammonia, which is used as a fertilizer up this way on farms.
These are temporary alternatives to flaring gas, and the most viable would be modular and be able to be moved from wellsite to wellsite as pipelines were emplaced as a temporary measure, and be reconfigured to produce marketable byproducts of what would have been flared gas which were most in demand in order to maintain economic viability.
This would be done because it would make someone money, not just for the heck of it.
I'm not a refiner, my work in in the extreme upstream end, working on wellsite steering horizontal wells using a combination of geological data from offset wells (where there are any), examining drilled samples and gas data from the wellbore while drilling, and using survey and gamma ray data from the MWD (Measurement While Drilling)guys.
However, I would think all the above processes involve drying the gas (removing water and other liquids), removing the heavier hydrocarbons (pentanes, benzenes and heavier), and separating out the light ends to liquefy them or burning them to produce electricity. Every site would have its own unique situation, proximity to major highways (paved roads), proximity to high voltage power lines (as opposed to just distribution networks), terrain challenges, cultural features, and distance to pipelines, and would have to be assessed accordingly in order to choose which option, if any, versus flaring would be preferable. (Cultural features would have to be taken into account: it is unlikely one would want to produce anhydrous ammonia, for instance, close upwind of or in proximity to any occupied structure, but especially schools or towns.
However, not being a chemical engineer, I can't say with certainty if the processes above would lend themselves to the sort of downsizing which would permit a temporary facility to work, both chemically and economically. There is no one-size-fits all solution to the situation at present, except flaring excess gas until feeder pipelines can be built.
Fracking has been a common practice in Texas and Oklahoma oilfields since the early fifties.
Originally, the fracking was conducted in vertical drillholes. But combining fracking with horizontal drilling is what has created the new oil and gas plays -- like the Bakken and the Marcellus.
I live in the Barnett Shale, where the process was first widely employed. The first well was drilled in 1993 -- and we've had no adverse effects for going on twenty years.
I live here in the Bakken. While most oil fields have a very pungent sulfur smell, there is no odor around these wells.
Conductor pipe (Similar to a heavy walled culvert) set at 60-90 ft. and cemented in place, that hole drilled with an auger type drill. This protects the near surface porous zones and keeps the material underlying the rig from washing out while drilling surface hole.
Surface: drilled using fresh water and whatever fine solids are picked up while drilling (making drilling mud), few additives to the mud except perhaps bentonite or cedar fiber to stop drilling mud loss.
This part of the hole generally extends down to about 2000 ft., and includes any aquifers in the region which are drilled into for water. The severe limits on additives limit the possibility of aquifers being contaminated while this part of the well is drilled. Generally the surface hole is 13 1/2 inches in diameter.
Surface casing, almost always 9 5/8 diameter is run in the surface hole and cemented in place. Sufficient cement is displaced to the surface to ensure a good casing bond, and this casing protects all the near surface strata from contamination by drilling fluid during the next phase of drilling, as well as keeps the wellbore stable and provides something to mount a wellhead and blowout preventers. The BOPs are pressure tested to ensure they work and that they do their job (every 30 days required, and when set up). The excess cement in casing is drilled out, down to the float valve which keeps the cement from u-tubing back into the casing after the casing is cemented but before it cures, and the casing is pressure tested. The cement is drilled out the rest of the way and a few feet of new hole drilled, then the casing and cement around it pressure tested to ensure there are no leaks in the system.
After that, the next part of the hole is drilled, usually 8 3/4 inches in diameter, down to kick off point, the directional assembly picked up, and the 'curve' drilled, bringing the wellbore horizontal around a roughly 410 ft. radius, and landing the curve in the target zone. This is done with oil based drilling mud here because there are roughly 400-500 ft. of salt down there which can cause hole problems with water based drilling fluids, usually due to washouts in the salt sections. Oil based ("invert") mud prevents those problems.
When that is done (usally landing between 9500 t. to 10500 ft. true vertical depth depending on which part of the basin), 7-inch intermediate casing is run and cemented in place. At that point there is a continuous seven-inch diameter pipe from surface to the target zone, cemented in place, inside the 9 5/8 inch diameter surface casing down to ~2000 ft., also cemented in place.
The BOP is reconfigured, tested, the cement drilled (now using salt water for drilling fluid because the salts are behind casing), the casing tested, the float and shoe drilled and new formation, and the entire system casing, BOP, cement job tested before proceeding to drill the horizontal part of the well.
If all this is done properly, and there are State (NDIC) checks every part of the way, the groundwater is safe form everything but surface spills, and great lengths are gone to to prevent surface down contamination. Drilling fluids systems are contained, (no dirt pits) and the location pad is constructed in such a way that any small surface spills will not reach groundwater.
Have they ever done a study on what happens geologically once the deep under ground rocks are pulverized by the water and sand ?
There have been a few studies done of frac propagation. A web search may give you more info than I can off the top of my head. The idea is to open pathways through which the oil can be recovered from the rock. Keep in mind that a 1mm fracture is a superhighway at formation pressures of 4000 + psi., so it doesn't take massive pulverizing to open up significant permeability in the rock.I read last night that nature does it's own version of fracking the rocks below.
I'd like to see that information if you have a link.
Most of the formations I work in are or contain significant amounts of carbonate material (Calcium Carbonate "Calcite" or Calcium Magnesium Carbonate "Dolomite", and those types of rock commonly lose porosity with compaction and depth of burial.
A lot depends on the geological situation, structure, groundwater, amount of tectonic activity in the region, and rock type.
This area is seismically stable, with no volcanic activity, so short of a major rock from space or the Yellowstone Caldera (fallout from that not direct involvement), we should be okay here (not allowing for acts of idiots in government).