The Williston Basin is a sedimentary and structural basin encompassing 52,000 square miles in North Dakota. The basin itself contains rocks from every geologic period from the Cambrian to the Tertiary. However, I am going to zone in on the late Devonian to early Mississippian aged units, or in and around the Bakken formation if you will. Organic-rich shales in the Bakken have been recognized as excellent petroleum source rocks and are believed to have supplied the large amounts of oil found in reservoirs above and below the Bakken.
During the Middle and Upper Devonian Epochs the Williston basin was a part of the larger western Canada basin of deposition. This was a time that was characterized by predominantly carbonate deposition with a thick evaporite in the lower part (Prairie Formation) and cyclical carbonate with some thin clastic and evaporite beds in the upper part (Duperow, Nisku, Three Forks). Deposition was continuous or nearly continuous into the Mississippian, but the center of the Madison depositional basin was nearly coincident with the present Williston basin. Mississippian deposition began with predominantly carbonate deposition, and evaporites increasing in the upper part.
The Three Forks Formation (Devonian) is roughly 250 feet thick and composed of shales, siltstones, dolostones, and sandstones. The Three Forks is a potential target for operators. Lying at the top of the formation is the Sanish Sand at the contact between the upper Three Forks and the lower Bakken Shale. Core analysis indicates the Sanish Sand is more Bakken related than Three Forks. The very fine-grained sandstone is highly burrowed and contains porosity and permeability similar to the Middle Bakken section. I’ll compare properties a little more when I discuss the Middle Bakken.
I’ve included a map showing Sanish Sand completed wells in order to get an idea of a spatial trend. Just an example of how Drilling Info can aid in various kinds of research.
Here is a map showing regional fractures in western North Dakota. The open tension fracturing along the Antelope field drape fold exposes the Sanish Sand for conventional and unconventional drilling methods.
The Lower Bakken Shale is very similar to the Upper Bakken with the main difference being thickness. The lower member is roughly 50 feet thick while the upper member is around 25 feet thick. Both are dark brown to black, fissile, non-calcareous organic rich shale. Both are pyritic and often thinly laminated. Average TOC is around 10% and even possibly as high as 20% in some areas. The rock is fairly fossiliferous containing brachiopods, fish teeth, bones, and conodonts. The fossil record indicates partially restricted marine conditions, evident by a neatly stratified water column. In other words, a quiet, deep, no turn-over, oxygen starved environment. This offshore setting is a key ingredient to an excellent source rock.
This brings me to the Middle Bakken, aka the “sweet spot.” This area is roughly 8 – 14 feet thick and around 75% oil saturation. However, middle member maximum thickness reaches 140 feet. From the Three Forks to the Lodgepole, only the Sanish Sand of the Upper Three Forks and the Middle Bakken siltstone have measurable matrix reservoir properties. The Middle Bakken being a little more porous and having a porosity value of around 8 – 10%. The Sanish has around 5-6%. Permeability in the Middle Bakken is around 0.05 md compared to the Sanish which is a little less than 0.1 md.
The depositional environment has a lot to do with permeability and porosity of the rock. The Middle Bakken was deposited during higher energy conditions. There must have been either regional uplift or a time of sea level regression in order to create this shallow water carbonate scenario. Basically, imagine low sea level during Three Forks deposition, high level during Lower Bakken, low level during Middle Bakken, high level during Upper Bakken, and then once again low level during Lodgepole deposition.
These rock properties and lithologies make the Middle Bakken a good place to frac. Plus, by having source rocks above and below, along with natural fractures, this allows for some of the best producing wells in the play. By looking back at the Regional Fractures map you can see the mass of wells in Mountrail County. Once again, using Drilling Info, I wanted to show some production values for Bakken completed wells in Mountrail County.
The Lodgepole Formation will wrap up this sequence. Also, sometimes referred to as the “False Bakken.” The Lodgepole is close to 900 feet thick deposited under normal marine conditions. The formation consists of limestones and dolomites. The Lodgepole is a major producing reservoir in Manitoba. However, the lower North Dakota Lodgepole or roughly lowest 100 feet of the formation would be best suited for any economically viable amount of oil and gas.
I look forward to more in depth look at production in respect to these reservoirs and plan to release a blog in the near future covering that. A good place to find more info on Williston Basin geology is the Geology Folder of Drilling Info DNA.
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The following is my quarterly, obligatory Hess Bakken update. After all, they are spending about ~$4B in the Bakken this year and acquired a significant amount of acreage entering 2011.
Judging by the permits, it appears Hess is actively developing a large part of it’s acreage as opposed to focusing on a few sweetspots. I am not sure what the leasehold situation is but I imagine that plays some sort of role. During the conference call Hess did mention that their newly acquired acreage may in fact be better than their legacy Bakken position.
They are operating 18 rigs this year and exited the 2Q at 25 Mboe/D. Hess, along with many other Bakken operators, reported significant delays thus far this year due to the weather. I live a long way from ND and the midwest in general but apparently the harsh winter combined with heavy spring flooding have wreaked havoc on oil and gas activity.
On the engineering front, Hess has changed it’s frac design to 38 stages. This includes 22 sliding sleeves, and 16 plug and perfs. 9 wells have been completed this way with 30-day average IPs of 1000 BOPD. Hess still projects EURs of 550 Mboe. Average drill time is down to 34 days and 7 or so to complete.
Hess will spend $400MM in Bakken midstream transport this year. Current takeaway capacity with Tesoro is 30,000 BO/D.
A Look At Top Bakken Operators
In light of a recent Brigham operational update, in which they discuss high performing wells all across their Williston acreage, I want to write about the top Bakken operators and where they are drilling. What parts of the basin are the best wells coming from and how does production change as you traverse the Basin?
First, some Bakken history. I pulled this chart from HPDI. It takes into account all Bakken wells from 2006 to present and presents the data on a county level.
Mountrail County has produced by far and away the most Bakken oil of any other county in the state. McKenzie, Williams and Dunn are the next few highest and interestingly have higher GORs (more on GORs later).
To get a better idea of recent activity, I restricted the rest of the data to the middle of 2010 onward. What I found was somewhat surprising.
The top operators have wells scattered across the basin in a much more balanced manner than I initially thought, my initial thoughts being that Mountrail would be the overwhelming “winner”.
I also looked at how production changes as one combs the entire basin. To do this I used the ever-versatile HPDI tools. I broke the basin into 4 regions based loosely on geology. The Nesson anticline runs N-S through the middle of Baken activity and separates McKenzie and Williams County from Mountrail.
My findings are illustrated in the charts below. Although Mountrail does get a boost from the 15:1 equivalency indicating a lower GOR, it is not up up and away the hands down place to be. The Nesson-South curve is dead on with the Mountrail curve. The last chart shows Mountrail is the most oily of the four regions. And interstingly enough, there does not seem to be a sharp GOR increase in the first 9 months. If you look at some of the other unconventionals such as Wattenberg Niobrara, the GOR curve through time exhibits a sharp increase. This could be the sign of something problematic occuring in the reservoir.
Check back for more updates, as always pass on your thoughts.
Yet another Hess earnings call was completed this morning, this the 1Q2011 earnings information. The Hess calls do not usually get into much detail regarding US onshore programs. Even though Hess is spending $1.8B in the Bakken in 2011, they have so many other assets that the focus tends to be more spread.
That being said, there was some new Bakken info during the call and Q&A. For one, Hess averaged 25 MBOE/D during the 1Q2010 and have a goal of 40 MBOE/D during 2011. They are currently operating 18 rigs, most of which is going towards HBP’ing their newly acquired American O&G and TRZ acreage. One other very interesting point which was discussed is the shift away from dual laterals. Hess has been touting the same dual lateral stats for over a year. $10-$11MM/dual lateral, 1 MMBOE / dual lateral EUR. According to Hess, they are moving towards single laterals for HBP purposes. This will go on for about 18 months.
Single lateral stats with an 18-22 stage job are as follows: $7-$7.5MM per, 550 MBO per, 30-Day IP of 700-750 bbl/D.
Below is a map of the last 6 months of Hess Bakken activity, this includes filings from American and TRZ.
The area to the NW I believe are the American Oil and Gas properties. The earnings call season is getting started which means PLENTY of good blog material. So if you are short on time available to listen to all the calls of your operators of interest, check back to this and the other Drillinginfo blogs, we will do all the leg work for you and present pretty Drillinginfo maps and charts to boot. If it is more in depth analysis you desire, shoot an inquiry to sales@drillinginfo.com and ask about DI-ESP Unconventional products.
Excluding the Elm Coulee field in Richland, County Montana, there is a relatively small amount of Montana Bakken activity. Below I have posted a few maps I generated while I was researching current activity. A permit search from the last 365 days returned about 100 Bakken permits. The company in North Sheridan County is called Taqa North USA and I am not familiar with their operations. The rest of the activity is in Roosevelt and Richland, EOG has been the most active, along with a host of other usual unconventional suspects.
A production search from 2010 to present returned 42 Bakken wells. These wells although few in number, are coming on at pretty impressive volumes. Enerplus has 12 wells represented with an average max monthly BO/D of 321 and an average 6 month cum of 48,000 BOE.
Another note of interest is how these operators are drilling infill wells. I blew up the sweetspot area in central Richland in this next graphic. I used the Drillinginfo symbol feature to signify the 2010 Enerplus wells, they are the teal squares. The offset wells were returned using the ‘Get Offset Well’ feature. Again, most of the offsets here are currently operated by Enerplus and drilled in the past 5 years or so. The offsets are colored by first prod date to get an idea of relative spud dates.
It is interesting to see how these unconventionals are evolving as they mature. DI-ESP has studied ‘cannibalization’ from infill development in the Wolfberry and Barnett. We are currently working to provide our subscribers with studies on spacing and infill development for other unconventionals.
There is a general consensus that longer laterals are the way to go in the unconventionals, but does the data suggest this practice is working, particularly in the Bakken? This entry deals with some of the data involved in this issue.
First, a look at how some of the top operators are drilling their Bakken wells.
ND is split into 1 square mile sections in the section township range system (STR). 1 square mile section = 640 acres, 2 sections = 1280 acres etc. For the rest of this entry I have defined two categories of Bakken laterals.
Short laterals: One-section laterals such as the EOG example. The surface to bottomhole distance can be up to about 7500′ if the well is drilled diagonally across the entire section.
Long Laterals: Two-section laterals such as the Whiting and Continental examples. Most of the new wells coming online are drilled in this fashion. I classify these as anything greater than 7500′, however the vast majority are up near 10,000′ since they span the greater part of both sections.
So, is there a production benefit to the longer laterals? This is something that we at DI-Energy Strategy Partners have been studying extensively. Here are some charts. The first one I binned the short and long laterals, ran a count and an average 6-month cum, then trellised by year.
These next charts are the same info just presented a bit differently. The top chart shows the long lateral, 6-month oil cums are increasing steadily with time while the short lateral 6-month cums peaked with the 2008 wells. The bottom chart shows the percentage breakdown of long vs short wells over each year since 2006. In 2010, almost 3/4 of the producing wells were long laterals.
Finally, a table of the top 5 operators for each lateral type. This is out of a sample of about 1800 Bakken producers with first production dates from 2006 to present.
What conclusions can be drawn here? For the majority of the modern Bakken long laterals have not been outproducing short laterals on a 6-month oil cum basis. It was not until 2010 that the long laterals overtook the short laterals. The same trend is seen with 12 month cums. However, the steady improvement of long lateral performance shown above is telling. As more long laterals are drilled, performance improves. This fits perfectly in line with the “learning curve” theory adopted by most and quanitfied by some of our past studies.
The data shows an industry switch to long laterals, but is this ultimately the best way to go? 10,000′ laterals are a tremendous engineering feat. Especially when considering a 30+ stage frac job. And I have seen quite a few engineering talks discussing heel/toe production disparities. The idea that most of the production comes from the heel suggests a series of short laterals can be an interesting alternative.
Factors such as marginal cost to drill the long lateral, shortages in frac crews and rigs, and urgency to hold sections play large roles in this as well. Leave a comment or email with some ideas/thoughts/feedback etc.
Continental Resources is one of the largest (maybe the largest) leaseholder in the Bakken at 865,000 net acres. They recently held the YE2010 earnings call and divulged some good information. Here are some notes away from the typical financials.
- Continental has 3 full time frac crews and 2 part time crews
- CLR is drilling with ECO-Pads at 3 wells per pad. This efficiency saves 10% in well costs. There has been a slight increase in well costs in the Bakken, about 6% for CLR, but this seems less than the Eagle Ford and Granite Wash. ND well costs are about $6.5-$7.0MM.
- CLR recently drilled two MT step outs. They IP’ed at 642 and 412 BOEPD, 24 stage fracs and cost $6-$6.4MM. This was a good step in shoring up CLR’s MT acreage, of which most of their 165k net acres is in this area north of Elm Coulee.
- ND Bakken EURs are about 518 MBOE.
- Current frac stage count is 30.
Below is a map of their Bakken producers, most of which lie on the Nesson Anticline.
Here is a slide from a March presentation showing a typical completion design.
Continental has established itself as a leader in domestic unconventionals producing impressive wells in the Bakken, Woodford, and the emerging Niobrara. They also have a position in the Paris Basin and expect to begin operations in the summer.
Hess has been saying the same things about their Bakken program for the last few quarterly calls, basically they are using dual laterals that cost upwards of $10MM a piece and EUR about 500 MBOE per lateral. This latest call, however, had a few extra tidbits which I’ll talk about a little further down. First, in case you have not been following Hess for the past few months, you need to get up to speed on a few acquisitions.
Hess bought American Oil and Gas and TRZ Energy last quarter. The American acquisition boosted their Bakken acreage by 85,000 net acres and the TRZ acquisition by 167,000 net acres. Both acreages are near their exisiting Bakken position which now totals > 900,000 net acres. Below is a Drillinginfo map showing recent producing wells from Hess, American, TRZ, EOG and Continental. I included EOG and Continental because they are two of the top operators in the area and give some perspective. The wells are bubbled by maximum monthly oil, the larger bubbles indicate more oil production.
Hess discussed well costs of $7-$7.5MM per single and $11-$11.5 per dual lateral. They have been fracking with 18 stages but have moved on to 22 stages currently. Their current 30-day IPs are 400-500 BOPD and Hess averages about 67% WI. They plan to double production in 2011 by averaging 18 operated rigs 40 MBOEPD.
I realize this is a Bakken blog but I want to talk some about their international unconventional activity. Hess has teamed up with Toreador Resources to explore the Paris Basin. They will spud by the end of 1Q and drill 6 exploratory wells in 2011. They will also begin drilling in the Daqing Field in China with Sinopec exploring unconventional targets.
Magnum Hunter recently acquired Canada’s NuLoch Resources in an effort to boost their Bakken activity. NuLoch is Calgary based company that has focused efforts in the Williston Basin in the US and Canada. The following is a map from NuLoch’s Dec. 8th corporate presentation showing their acreage in North Dakota and southern Saskatchewan.
This is only a portion of NuLoch’s activity in North America and is focused on the Bakken and Three Forks. They also have activity in Alberta as seen in the following map of NuLoch wells in HPDI.
The deal was an all common stock transaction for roughly $327 million which includes ownership interests in 67 wells with productive capacity, a six rig drilling program in the US and Canada, and approximately 71,600 net acres in leasehold. Magnum Hunter will add these assets to their 15,000 gross acres in the Williston basin, some of which are close to the acquired acreage from NuLoch in Burke County. The following is Magnum Hunter acreage in the Williston Basin as reported on their website.
Magnum Hunter made a similar deal at the end of 2010 for an Appalachian Basin focused company called NGAS Resources for $98 million.
I came across an informative interview of Kirk Wilson from The Energy Reporter on seekingalpha.com. Mr. Wilson discusses the Alberta Bakken Trend with a focus on valuation of the players more so than detailed geology. The Alberta Bakken Trend is in Alberta and Saskatchewan, and bleeds into central Montana.
There are some insightful takeaways from the interview. For instance, the royalty rates in Canada are much lower than in Montana. Mr. Wilson cites a 30% royalty rate in Montana, while in Canada initial royalty rates are on the order of 5% and as low as 2.5%. The impact these low rates have on economics is significant.
He brings up the point that the Alberta Bakken is light oil compared with the heavy oil of the Williston Basin Bakken. He throws out 35-42 degree API gravity. At 4,500′-6,000′, the depths are much shallower than the Williston. This results in much lower drilling costs, $4MM vs $7MM in North Dakota.
The Alberta Bakken is new and emerging therefore data is at a premium. I have a map of 2010 Montana permits below, histogrammed by operating company. There are two main clusters, the cluster in East MT is associated with the Williston Basin, while the cluster in Toole and Glacier counties are Alberta Bakken.
The two main Montana players actively drilling that I have been hearing about are Rosetta and Newfield. Newfield has 10 permits and Rosetta has 6. There is no Bakken production data in these two counties as of yet in the Drillinginfo database. Drillinginfo is actively entrenched in a Montana leasing project to include leases as well as lease polygons for these unconventional counties.
More on other players and some Canadian data later.