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PN Bakken: ND’s gas woes
Petroleum News ^ | Week of December 02, 2012 | Ray Tyson

Posted on 12/05/2012 6:12:46 AM PST by thackney

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To: DesertRhino
" Hey, stop thinking outside the box. "

But that's the kind of thinking that will make progress in this situation instead of relying on " Conventional wisdom " when folks say " it can't be done " or " it's to hard " .
41 posted on 12/05/2012 10:49:58 PM PST by American Constitutionalist
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To: American Constitutionalist
Most everything in this region is mounted on skids and moved by winch trucks. You might have seen similar if you watch Ice Road Truckers long enough. Rail lines are as far apart as major highways, farther, actually. Currently oil is being trucked to rail head loading facilities and going out on unit trains. Some of that oil likely would have hitchhiked on the excess capacity of the Keystone XL Pipeline...and some is being pipelined out on existing lines.

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.

42 posted on 12/06/2012 1:03:59 AM PST by Smokin' Joe (How often God must weep at humans' folly. Stand fast. God knows what He is doing)
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To: Smokin' Joe
I may not be a engineer, but, keeping my mind busy of finding a economic/viable infrastructure way to tap into a resource that other wise would have to be flared off until those pipelines are built.
How safe are those wells in regards to the ground water once they have put in place the safety net of putting down into the wells below the water table the concrete casing and metal casings ?
If done properly ? the ground water is safe from contamination ?
Have they ever done a study on what happens geologically once the deep under ground rocks are pulverized by the water and sand ?
I read last night that nature does it's own version of fracking the rocks below.
43 posted on 12/06/2012 8:04:19 PM PST by American Constitutionalist
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To: American Constitutionalist
Have they ever done a study on what happens geologically once the deep under ground rocks are pulverized by the water and sand ?

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.

44 posted on 12/06/2012 8:26:44 PM PST by okie01 (THE MAINSTREAM MEDIA; Ignorance on parade.)
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To: Smokin' Joe
The Bakken oil (and gas) is sweet, too, and the absence of significant amounts of sulfur will make action against flaring more difficult.

I live here in the Bakken. While most oil fields have a very pungent sulfur smell, there is no odor around these wells.

45 posted on 12/06/2012 8:39:20 PM PST by upsdriver
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To: American Constitutionalist
Well construction, Williston Basin 101: (State regulated, with reporting and checks done).

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).

46 posted on 12/06/2012 10:01:08 PM PST by Smokin' Joe (How often God must weep at humans' folly. Stand fast. God knows what He is doing)
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