Posted on 06/19/2014 12:56:00 PM PDT by george76
Crescent Point’s Torquay Discovery Reignites Southeast Saskatchewan.
Just when you thought The Bakken couldn’t get any better—it does.
Oil producers are now “cracking the code” on the Torquay, or Three Forks formation below the Bakken, and coming up with incredible economics—these wells are paying back in only seven months.
This news has completely re-invigorated the Canadian side of the Bakken. And on the US side, the Three Forks is causing industry to leap-frog estimates of the amount of recoverable oil available–by about 57%!
It’s hard to imagine that the #1 oil play in all of North America could have such a huge increase in size—usually this happens in increments. This map from the Province of Manitoba shows how much potential theTorquay/Three Forks has—it ranges from 1.5 – 7 x as thick as the Bakken!
(Excerpt) Read more at oilvoice.com ...
The project used a megapad containing 14 wells targeting multiple, stacked pay zones. Included were four wells targeting the Middle Bakken, three targeting the Three Forks 1, four targeting the Three Forks 2, and three targeting the Three Forks 3.
The unit, which spans 1,280 acres, tested at an initial combined monthly rate of 14,850 boe/d from all 14 wells.
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It is frustrating they only gave the combined data and not the individual.
Which pretty much conforms with my observations. There are places where the third bench will have shows and likely be productive. I do not expect that to be as widespred as Second bench production, nor do I expect that to be as widespread as the first bench production. There are hotspots in the play which will produce from all three of those benches and possibly the fourth, but in my experience, I have not noted shows in the fourth bench in vertical wells. That doesn't mean they do not exist, just that the wells I worked were not in the areas where they do.
I have been working in the Williston Basin as a wellsite geologist since '79, and have been doing Bakken horizontals since 2000. I'm on a wellsite now.
I won't say I have described more Three Forks or Bakken section than everyone else, but I have done quite a bit over the last 14 years. Before horizontal wells really came into vogue (I have been working those since 1990) I had noted oil shows in the Bakken and Three Forks pretty consistently, as I mentioned. Running open hole drill stem tests on the formations was out of the question, generally, a combination of difficulty in getting a packer seat and the shale sloughing when the tool was opened, either plugging the tool or sticking it in the hole. Company hands would look at a geologist like Van Helsing looks at Dracula for even suggesting a DST, so the Bakken and Three Forks were pretty much relegated to salvage zones, to be perforated if the shows were really good after plugging a deeper objective.
One well vertical well I worked in 1980 was a Bakken producer, but that was pretty obvious, as shows go, making 500MCF (sweet gas) and 70 bbls of condensate a day out of 4 feet of perfs, done on my strip log because the e-logs were too gas invaded to be of much use. In those days that was considered a fairly good well up here.
Horizontal drilling has completely changed that perception.
The unit, which spans 1,280 acres, tested at an initial combined monthly rate of 14,850 boe/d from all 14 wells.
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It is frustrating they only gave the combined data and not the individual.
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So lets presume the worst case. The profound success of one or more of the wells at one or more levels is covering up a poor performance of one or more wells at one or more levels.
Would I presume wrong if I presumed that with 14 wells on a pad, the cost per well goes down considerably. Such that even a well that brought up 400 boe/d would be economic—because the incremental cost of drilling another well is much less once the pad and set up is established and paid for.
I don't think pad costs are significant.
But what does go down, assuming they are using something like a walker is the set-up & tear-down between wells. The wells themselves would have little changed.
The cost/time to tie into production, gas line flare, etc goes down with a combined service.
So lower cost, but not much lower, most of the money in the well hasn't changed.
Ok thanks. take a look at Smokin’ Joe post at 42.
He’s been a long time in the Bakken.
His take is not out of line with EOG’s lightening up on Bakken and concentrating on Eagle Ford. Plus the fall off of Core Lab business in Bakken.
That is it may well be that the three forks formation is spotty—much spottier than the bakken levels above.
So lower cost, but not much lower, most of the money in the well hasn’t changed.
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So when they use the word “economic” they mean the well is profitable but we don’t know how profitable. They would hide that little fact because?.....
More data please.
Because they don't likely know. Oil business economics is hit or miss sometimes on wells right next to each other. It is a higher risk business than most. That rock/shale has changes in geology sometimes in very short distances. It is not a uniform structure. Think of it as differences in soils, sands, hills, drainage on the surface occurring underground.
“The project used a megapad containing 14 wells targeting multiple, stacked pay zones. Included were four wells targeting the Middle Bakken, three targeting the Three Forks 1, four targeting the Three Forks 2, and three targeting the Three Forks 3.”
Actually they used 5 different pads at Hawkinson
You can check it on NDIC website
“Which pretty much conforms with my observations. There are places where the third bench will have shows and likely be productive. I do not expect that to be as widespred as Second bench production, nor do I expect that to be as widespread as the first bench production. There are hotspots in the play which will produce from all three of those benches and possibly the fourth, but in my experience, I have not noted shows in the fourth bench in vertical wells. That doesn’t mean they do not exist, just that the wells I worked were not in the areas where they do.”
Am curious, do you ever see a lack of oil saturation in cores of lower benches of 3F that still produces satisfactory?
Many of the wells appear to be nonprospective so my conjecture is frac extending up to Middle Bakken.
Most places the Middle Bakken produces, the upper level of the Three Forks will likely do well also, because the Lower Bakken Shale is the source rock for the Three Forks oil, and the shale will have reached thermal maturity.
Whether that will extend down section into lower levels will depend on the amount of oil generated, natural fracturing (and structure) and may turn out to be at least partially structurally dependent, if for no other reason than the development of fractures on structure. Those may be short-lived as migration pathways, I have seen Bakken core from south of Tioga which was fractured, but the fractures were healed by calcite.
Whether the frac propagates far enough vertically is a good question, but you would think with Middle Bakken production already in existence where the Three Forks is being completed, pressure changes would be evident in the existing well if there was communication during the frac.
From what the production hands have told me, the frac tends to propagate along the bedding planes and follow paths of least resistance, which makes staged fracs better for fracturing the tighter layers.
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