Weld County Update: Recent Trajectories In The Niobrara’s Oil Core

Weld County Update: Recent Trajectories In The Niobrara’s Oil Core

In the current oil-price environment we have all seen the tremendous decline in the number of active rigs across the country, in part led by steep attrition in the far-from-market Bakken and the less bountiful non-core acreage in the Eagle Ford. But there have been a few play areas that, though they have certainly suffered from the downturn, have kept activity levels up better than the national norm.

Previously we have discussed Oklahoma, led by its STACK and SCOOP; the Permian Basin’s Midland and Delaware basins, and recently the Utica Shale in Ohio.

But there is one play that pops up in a lot of operator presentations and analysis and news that we haven’t touched on recently, the mighty Niobrara, and in particular the oil rich donut of acreage in Weld County, CO.


The rock is always the most important factor, so let’s start there. I asked one of the geologist’s upstairs (Tiffany Guiltinan) to send me some info on what their team has been working on in Weld County. This first image breaks down the different tops that the team has identified and picked throughout the play area (the Chalks and the Marls, etc.), and also the resulting zones (Niobrara A, B, C, Fort Hays, etc.). On the right is an example of the impact faulting can have on a section – in this case the Fort Hays limestone has been faulted out in the second log from the right. She wasn’t sure if that was interesting or not, but I thought it was.
Weld County fig 1

She also sent me a few charts related to the work the team has been doing with corroborating directional surveys to the different zones.

Weld County fig 2

The upper left chart shows that the Niobrara B (with 43%) and C (with 23%) are clearly the most popular landing zones. The lower left shows that two thirds of Weld County horizontals are using a toe-down trajectory (more on that later). Upper right shows that most wells have a horizontal length around 4000-4500 ft, and lower right shows that most wells are going north/south or east/west.

If you want a little more background on the geology of the Niobrara, you can refer to Tiffany’s excellent post on the Smoky Hill Member, and Clint Barefoot’s The Niobrara Shale Formation – From Idea to Action in 10 Minutes.

Weld County Production and Drilling

Before we go too much further, lets add a little geography to mix, so we know where we are. For wells that have been brought on line in the past 5 years in Weld County, we see the donut-ring of oil production surrounding the donut-hole gas production in the southwest part of the county.

Weld County fig 3

And looking at the same area, with active permits, we can see where some of the bigger name operators are focusing their activity.

Weld County fig 4

One of the most striking parts of the permit image is the lines of permits that line up straight north/south or east/west. Hmmmm.

If we zoom into the area near Riverside Reservoir in the middle of the map, on the left we see when the permits go north/south, the wells go east west, and then when we overlay our (new) landtrac lease outlines, everything becomes clear. Since Colorado lines up their mineral rights in a PLSS system, lining up your wells along one edge and drilling to the other edge makes total sense.

Weld County fig 5

The Heel and The Toe

I said I would get back to toe-up vs. toe-down trajectory. Consider the following well.

Weld County fig 6

This is a well from that region near Riverside Reservoir. The red line represents the directional survey of the well as ingested and QCed by our data team. The colored areas represent the limits of the various   zones as picked and QCed by our team of geologists. We determined the “heel” by selecting the point at which the well achieves an 80 degree from vertical in the survey (the blue point on the left), and the “toe” is the end of the well (the blue dot on the right). So in this case the toe is lower than the heel, whereas had we used, say, 88 or 89 degrees the toe might actually be higher and therefore “toe-up.” Also of interest is the fact that in this case the geological stack of formations is trending downwards , which means the hydrocarbons from the toe are going to be from the top part of the formation (in this case the Niobrara C), while nearer the heal  they will be from the middle of the formation. Oh, also this well is drilled at an average azimuth of 88.94 degrees, meaning it is going from the west to the east.

Weld County Rig Activity

Speaking of toes, perhaps we can see a little bit of an upturn at the toe of this chart of rig activity in Weld County?

Weld County fig 7

On the left we see the larger class rigs, capable of making the turns and keeping on schedule, have come to dominate the landscape, and on the right we see that, as expected, PDC, Whiting, Noble and Anadarko have taken over most of the action.

Your Turn

What do you think? Leave a comment below.

Utica Shale: Appalachian Basin Oil & Gas Geology and Activity

Utica Shale: Appalachian Basin Oil & Gas Geology and Activity

Since there hasn’t been much news out of Ohio this week, I thought it would be a good time to revisit the Utica Shale.

Wedged between the Cincinnati Group and the Black River Group formations, deep below Ohio, Pennsylvania, West Virginia and even parts of Canada, lies the Middle Ordovician stratigraphical unit we have come to know as the Utica Shale.

Utica Shale Geology

The Ordovician came on the heels of the mass extinction event that ended the Cambrian period, and the Middle Ordovician (the tail end of a greenhouse cycle that extended back well into the Cambrian) was notable for high sea levels and marine temperatures that are assumed to be ~113 degrees Fahrenheit. Laurentia, the “continental craton” that forms the ancient geological core of the United States, was one of the 4 major landmasses in play (along with Gondwana, Balticia and Siberia). This map of The United States superimposed with the Middle Ordovician version of Laurentia shows a substantial basin stretching across much of our area of interest. This hot marine bed encouraged an explosion and accumulation of macro algae and other simple life forms that, 460 million years later, have become the hydrocarbon focus of this blog post.

Utica Shale fig 1 appalachian basin oil

Today’s Appalachian Basin Oil & Gas

Mostly when we talk about Oil & Gas in the Northeast, we talk about the huge resource of dry gas that unconventional E&P has brought online, and for good reason. The unbelievable growth of natural gas production has turned east coast LNG import facilities into LNG export facilities, and, by supplanting coal with much cleaner burning Natural Gas, have made the USA the leader in lowering CO2 emissions. Most of this dry gas comes from the mighty Marcellus Shale, and early unconventional exploration in the Utica Shale was also focused on the dry gas resource.

However, current E&P in the Utica is focused more on the liquids rich portion, particularly in the state of Ohio. On the left of this image we see the extant of the Utica in yellow and the 50,0000,000 year younger Marcellus outlined in black. Additionally we see the Utica depths in the green tops – notice how it tends to be shallower to the west. The fantastic map on the right shows the different play areas of the Utica, and we can see both wet gas and oil windows prevalent in Ohio. The two images together make a pretty good case for Ohio focused Utica activity.

Utica Shale fig-2 appalachian basin oil

Point Pleasant Formation

The Point Pleasant is also a Middle Ordovician formation that is interlayered with the Utica Shale. Both formations have similar TOC estimates, but the Point Pleasant is generally regarded as the sweet spot of the oil window.

Utica Shale fig-3 appalachian basin oil
Image Source: https://geosurvey.ohiodnr.gov/portals/geosurvey/energy/Utica-PointPleasant_presentation.pdf

Appalachian Basin Rig Activity

First, some good news for everyone who makes money when rigs are running. Here on the left is our current National Daily Rig Count from the newly redesigned DI Index Page (y’all should check it out – it’s got more interactivity, and you can read this month’s perspective), and on the other side, DI Rig Analytics, we see the very familiar US Onshore decline over the past 18 months.

Utica Shale fig-4 appalachian basin oil

On this next image we see rig count activity for Ohio Utica or Point Pleasant wells contrasted with the Eagle Ford play. We can see although there are still quite a few more rigs by number in the Eagle Ford, the attrition has been much steeper there than in the Utica. We will talk about Utica/Point Pleasant operators more a little later, but we can clearly see there are fewer of them engaged. As for the Eagle Ford, I thought it was pretty striking how the more powerful rigs have come to dominate activity – it stands to reason of course, but here we see it in the data.

Utica Shale fig 5-1 appalachian basin oil

Next lets compare the rig count drop of Ohio’s Utica/Point Pleasant with the state of Oklahoma. For both areas of interest we see that the attrition has been calmer than the national and Eagle Ford charts. The activity in Ohio has mostly been focused on 5 or so of the 12 that have Utica or Point Pleasant targets. On the Oklahoma chart we see that, compared to Mid-Continent, the Anadarko Basin has had even less drop off.

Utica Shale fig 6 appalachian basin oil

Utica/Point Pleasant Permitting

The lion’s share of Utica/Point Pleasant focus has been in Southeast Ohio’s Belmont, Monroe, Harrison, Jefferson and Carrol Counties. The next image shows the last 18 months of permitting for those counties. Horizontal permits account for over 2/3 of the activity, and the positioning by operator on the map show’s the various fairways that are involved in the exploring this liquids-rich area.

Utica Shale fig 7 appalachian basin oil

The Aubrey McClendon founded American Energy – Utica LLC changed it’s name to Ascent Resources – Utica mid-summer 2015, and between them they have filed the most permits over these five counties in the past 18 months – 232 vs. runner up Chesapeakes’ 173 permits filed.


The shallower, less organically mature, and more liquids-rich portion of the Utica/Point Plesanat in southeast Ohio is worth keeping an eye on, particularly as we see more stable pricing return to the energy market.

Your Turn

What do you think? Leave a comment below.

From the Niobrara to the Marcellus and Beyond: Noble Energy

From the Niobrara to the Marcellus and Beyond: Noble Energy

Lloyd Noble’s namesake Noble Energy (founded in 1932) has long been an important and innovative operator in Oil & Gas Exploration and Production. Their current portfolio of international and domestic projects include offshore Gulf of Mexico and West African operations, as well as leadership positions in the US Marcellus and Niobrara plays. They are also one of the first players to take advantage of the current oil price climate with their recent acquisition of Eagle Ford and Permian Basin Operator Rosetta Resources for $2.1 billion.

That acquisition and their recent presentation at UBS prompted me to take a deeper look at some of their US operations.

The Niobrara

The Niobrara in Northern Colorado/Southern Wyoming has been getting a lot of attention for its tight oil formations – in fact recently small cap operator Bill Barrett declared that $55-$65 oil will be a perfectly adequate environment for their E&P.

Noble is one of the dominant producers in the DJ Basin and the Niobrara in general, having made a commitment to the play for the past 5 years. Currently they are running 4 rigs, and are optimizing their operations with a focus on lengthening their laterals and decreasing time to drill.

The Geology of the Niobrara is quite complex, and has multiple formations that are prospective for hydrocarbons. To give you an idea of this complexity, take a look at this SW to NE geological cross-section in Weld County (from our Drillinginfo Niobrara Geology Play Assessment) flattened along the base of one of these formations (in this case the purple line/marker shows the base of the B Bench). Notice the general thickening of the Bench (the top of the B Bench is the red line, the pink is the “peak” or midpoint) as we move to the northeast.

Untitled-4 Noble Energy

The Marcellus

In 2011 Noble partnered up with coal-giant Consol to develop gas acreage in the heart of the Marcellus. With a strong presence in both liquids-rich and dry-gas focused counties of northern West Virginia and western Pennsylvania, Noble continues actively drill and innovate in their completions, showing an improved horizontal volume up 330% vs. their 2012 completions. Recent upgrades to the pipeline network, as well as Dominion Cove Point’s continued progress towards a Liquefied Natural Gas (LNG) liquefaction terminal in Maryland are only going to increase Noble’s options in the future.


Speaking of liquefaction, The Sabine Pass and Corpus Christi LNG projects are well underway, which is good news for the acquired Rosetta Eagle Ford acreage in The Southern counties of Dimmit and Webb which is in the heart of the dry gas acreage for the play. The balance of the Rosetta acreage in both the Eagle Ford and Permian Basin plays are very promising for oil production, with additional long-term stacked-pay potential in the Permian Acreage. It will be interesting to see what Noble’s commitment to optimizing their engineering practices will bring to Texas.


Noble Energy is well-diversified across onshore US tight oil plays with a strong drive to innovation, and the ability to capitalize on lessons-learned. Add to that an aggressive and smart global offshore exploration program – with new developments off of Israel and the Falkland Islands – and you have an operator worth watching, perhaps for another 80 years.

Your Turn

What do you think? Leave a comment below.

The Niobrara Shale Formation – From Idea to Action in 10 Minutes

The Niobrara Shale Formation – From Idea to Action in 10 Minutes

The Niobrara Shale formation is an attractive and exciting shale oil and gas play that is often compared to the Bakken.

Although the play is in its early stages of development, operators have been quickly leasing land in the core zones, especially in the Weld and Yuma Counties in Colorado, and Cheyenne, Kansas.

The play ranges in thickness from 275 – 400 feet in depth, with three primary carbonate-rich benches that average roughly 10 – 25 feet thick with roughly a 5-10 percent porosity.

Oil and natural gas is trapped between 3,000 – 14,000 feet below the earth’s surface. Operators are extracting the resources from the Niobrara shale formation by drilling vertical and horizontal wells at a depth of roughly 7,000 – 8,000 feet.

Although the Niobrara’s geological characteristics can impede effective, economical drilling, the impressive oil and gas production estimates have attracted significant E&P capital investments from some of the top oil and gas operators.

Such impediments include high clay content of the formation, water shortages and the geological transitions from limestone to chalk to calcareous shale to sandstone – each with differing depths and thickness.

For many of these reason, Niobrara shale operators are seeking sections that have a high natural fracture density – which are likely more productive and easier to tap – compared to reservoirs characterized by a lower fracture density – which yield elevated water cuts and reduced output.

The following analytical work-flow of the Niobrara using DI Data and Transform software is designed to help alleviate these hurdles, provide a thorough evaluation and a competitive advantage for DI users.

A Rapid Reconnaissance of the Niobrara Shale Formation:

Let’s assume that an opportunity has arisen that demands a quick evaluation, and we lack time for a full in-house pre-project analysis.

In order to avoid an inherently flawed opportunity evaluation, it’s important to begin an analysis with hyper-clean data.

Using data from DI Analytics, we can easily review the operator statistics table and determine that there’s a significant amount of production in various zones. We’re able to see co-mingled productions, outputs from the A, B, and C benches and the Codell as well.

Matching the production to the correct geological section can sometimes be a challenge, but we can easily segment the information using highly-detailed filters, avoid project build hassles and quickly evaluate an opportunity.

We’re then able to export data and quickly get a CS feed that includes information like the API number, latitude, longitude, well name, operator name – anything that is required for a project analysis.

For the purpose of this analysis, we’re only going to compare Niobrara production from horizontal wells, so we didn’t include any production from the Codell or any co-mingled production.

Thanks to our Drillinginfo geoscientists, who have dedicated roughly two years to correlating events, picking tops and faults, we have access to over 6000 wells and gamma ray logs in the Niobrara Basin.

From here, we’ve created 38 key structured structural, isopach and property maps in high-resolution from the interpretations.

Here, using Transform software, we’ve generated a 3D view of the Wattenburg Field in the Northeast. We can see a structural map of the top of the Niobrara and compare the depths of various regions.

niobrara shale 3D scene of wellbores3D scene of wellbores. Multi-pad drilling, completion of multiple zones common.

From this view, we can identify how operators are completing their wells simply by zooming in on the populated well-bores. Most look to be multi-pad drilling, deviating out and then hitting multiple zones.

Then, we can flatten out the A Bench top and see the thickness of the A bench. There appears to be some syndepositional tectonic influence in the selected region, resulting in a thicker Niobrara section. This gives us a good look at the structural history of the region’s geology and a quick interpretation.

niobrara shale Cross-section from the SW to the NE flattened on the top of the A BenchCross-section from the SW to the NE. Here we are flattened on the top of the A Bench. We can see the A Bench thickness changes across the transect as well as some probable tectonic influence in the SW.

With our high resolution interpretation and the analytics-ready data focused only on Niobrara horizontal production, we can then use cross-plots to evaluate specific variables.

A quick look at these cross-plots show that thicker B Bench and API gravity between 42 and 52 is optimal. The image shows how we can quickly grid the B Bench thickness while also highlighting points in the optimal API gravity on our basemap.

niobrara shale individual property types and their effects on productionHere we are looking at the individual property types (thickness of B Bench, oil gravity, porosity, horizontal wellbore length) and their effects on production. In the map view we are showing an isopach of the B Bench and highlighted wells in the wet gas window of oil gravity. Some areas of the thickest B Bench are in this optimal wet gas window.

Next we can build a multi-variate statistical model to predict oil production. We are using a handful of geological attributes as well as horizontal well length. Through this model we are able to predict oil production with a 0.660 confidence level.

The map shown in the image is the oil prediction map for the first 6 month of production. This map has stacked the geological properties by significance and normalized out the true statistical effect of horizontal well length.

niobrara shale individual properties by significanceHere we are stacking the individual properties by significance to predict oil production. We can also look inside the model to make sure the individual contributions make scientific sense.

By reducing the time needed for interpretation and data conditioning combined with an interpretation package that allows for easy statistical analysis, we quickly created a map that we can use to evaluate opportunities.

niobrara shale high predicted oil productionThis map shows areas of high predicted oil production. This is created using a multi-variate statistical approach where we stack the individual geological properties by significance and we normalize out the true statistical contribution of horizontal well length. Included in the map are some interpreted major faults and some structural contours.

Your Turn:

The workflow outlined above was a big hit at SEG 2014. The process can be easily applied to a variety of top shale plays, and expanded upon by adding geophysical and engineering data.

How would you use the features outlined above to improve your project analyses? Let us know in the comments.

A Utica Shale Update

A Utica Shale Update

The scope of this blog post is to take a quick snap shot of the recent activity in the core of the Utica Shale play of eastern Ohio and western Pennsylvania. Drillinginfo offers a suite of tools to gain this knowledge quickly and accurately. Well permitting is always a pretty good start; however, something to keep in mind is the importance of including the Point Pleasant in the query when performing this search. According to the USGS, the Point Pleasant is a Limestone (60%) inter-bedded with shales (40%) which serves as an effective perforation interval below the Utica Shale. The Trenton Limestone (below the Point Pleasant) is also a relevant reservoir to the play. The following chart showing permits approved this year highlights this observation.

Utica Shale Utica Trend Target Formation

Utica Shale Utica Trend Operator

Leasing is also another good indicator of play activity. The two tables below reflect the leasing record counts for Ohio since the start of 2014.

Utica Shale Ohio Leasing

Finally, spatial representations of the play core sort of sums up a brief play overview. The map below showcases the sweet spots discovered thus far. This includes wells reported as Utica, Point Pleasant or a combination of the two. Trenton is not included.

Utica Shale Peak BOE

Since production is reported annually in Ohio, wells shown reflect the peak month of rate in order to provide the largest data set available. Usually, this is the first full month or second month of the well’s productive life.

The Utica/Point Pleasant is a respectful unconventional resource play that has gained the attention of both domestic and international investors over the past few years. However, the play has not quite proven itself on productivity basis to rival the economic Eagle Ford, the prolific stacked potential of the Permian Basin or the mighty Bakken.

Your Turn

What do you think? What are your thoughts on the potential of Utica productivity? What would you predict to be the most effective driving to help the play reach its full potential? Leave a comment below.

Oklahoma Oil and Gas: Woodford SCOOP Wells Have Stamina

Oklahoma Oil and Gas: Woodford SCOOP Wells Have Stamina

The Woodford Shale itself is not a new Oklahoma oil and gas play and while some plays begin to lose hype over a few years, there is still quite a bit of emerging play buzz going on, especially in the southern portions.

The Woodford SCOOP, or South Central Oklahoma Oil Province, as coined by Continental Resources a couple of years ago, has grabbed the attention of a handful of large operators.

Continental, the clear leader in the play, plans to spend almost $900 million in 2014 to SCOOP development and exploration – almost double what the company spent in 2013.

What Makes This Play So Attractive?

As most folks already know, the SCOOP is a liquids-rich play, offering high yields of oil and condensate. However, only a few years ago, the Woodford was sought after for its natural gas production, especially in the Arkoma Basin. Here is a map showing the entire Woodford play area broken down into four play regions based on the basin of deposition, GOR, primary product and industry drilling trends. Each well is bubbled and colored by its max month of oil production in barrels per day. This gives a brief, high-level overview of the Woodford’s sweet spot areas and shows the variation in the Woodford’s hydrocarbon thermal maturity.

SCOOP-Woodford-MaxIP Oklahoma Oil and Gas

What’s Going on in the SCOOP?

With that better idea of the Woodford as a whole, I queried up some data and looked for trends or standout data points that make the SCOOP play area special. I used the customized, DI Analytics dataset for my observations. Some of the power users of these datasets call them “analytics ready” and allow for faster workflows and quicker data to answers interpretation.

SCOOP-Woodford-OilTypeCurve Oklahoma Oil and Gas

I want to look at similar plays to make sure I’m not comparing apples and oranges here, so I decided to hone in on the Bakken and Eagle Ford Oil Window since these plays compare favorably in terms of the product produced and GOR. Right off the bat, what stood out was short-term cumulative production levels of Woodford SCOOP wells compared to these other two plays. Observe the table below:

SCOOP-Woodford-CompTable Oklahoma Oil and Gas

The major points of interest here are the lower initial decline rates, which account for the first 12 months of the well’s production. This is indeed an attractive attribute of the play considering typical shale wells decline 55 %– 70%, roughly, within the first year of production.

Through the Looking Glass

While this hardly comes close to solving the “Red Queen” conundrum of needing to produce more and more just to keep up with rising demand, it does allow a minute to stop and reflect. The ability for a well to produce at strong levels long-term with favorable rates of return in the 45- 55% range (assuming $3.50/Mcf, $90/bbl and $9 MM completed well costs) is nothing to scoff at. You could expect even better economics as the play matures and well costs decline.

What Else Should We Know?

In 2010, the USGS assessed there to be about 16 Tcf of dry gas, 400 MMbbls of recoverable oil and about 250 MMbbl of condensate in the SCOOP. While this holds promise and potential, the play area also presents plenty of challenges.

  • The Woodford, whether it is Ardmore or Anadarko Basin, lies at a depth deeper than most other unconventional resource plays. This accounts for higher well costs usually in the range of $8-$10 million, with extended laterals even more costly around $13 million.
  • There is also the complex geological structure and mineralogy of the Woodford adding to the equation, a topic worthy of its own blog post.

These are just a couple of possible reasons why the SCOOP hasn’t attracted more operators to the play. Nevertheless, this is always an interesting phase of play development when operators have staked out their position, drilled a few wells, and started applying techniques and expertise gained from other unconventional resource plays to evaluate what works for well productivity. It will be fascinating to see further development unfold in the months ahead.

Your Turn

What do you think? Why do you think the lower initial decline rates are so much better in the SCOOP? Is it too late for other operators to get in the play? Please leave a comment below.