The headlines continue to highlight positive developments by operators in the SCOOP/STACK plays in Oklahoma. But who is participating in the production streams BESIDES the operator? What non-operated interests or overriding royalty interests are participating right alongside the operator?
Or who was the initial grantee actually leasing for?
We’re lifting the curtain with the release of assignments in the SCOOP/STACK—in a big way!
Here’s what we’ve released..
Find out what’s been assigned—and what’s not been assigned…yet. Create AOIs around the areas that you want to watch for future opportunities, and do it with this level of detail.
Not only can our customers view assignments online within Drillinginfo, they can also create a leasing report in Drillinginfo for areas that they’re interested in. An example is this report on Kingfisher County, OK (STACK play) which shows 1 of 11 new leases taken as recently as 3/15/2017.
Use this tab in Drillinginfo to start creating custom reports.
Combining customized leasing reports with the power of our DI SCOOP/STACK play assessments is a powerful enhancement to operators who want to unlock current opportunities in these plays.
On November 16, 1907, Oklahoma became the 46th state to enter the Union. About a decade before that, in the then Indian Territory, Miss Jenni Cass dropped a “go devil” detonating device downhole and The Nellie Johnson no. 1 well became the first commercially viable oil well in the Territory. Fast forward to July of 2015 and we find the State of Oklahoma contributing the 6th most crude oil and 3rd most natural gas in the country. Not only is Oklahoma therefore in a combined 5th place in terms of energy resource production, it is also the home to the Cushing hub, where orders for West Texas Intermediate (WTI) oil futures are settled for the New York Mercantile Exchange.
Much of the news that comes out of Oklahoma lately centers around the disposal water quake controversy, and relative financial health of a few of the very large operators who are headquartered there. The recent selection of Paul Ryan as Speaker of the House has an interesting Oklahoma angle given that his wife Janna Little Ryan’s family has a rich Oklahoma political history. (Their family dogs are Boomer and Sooner).
Of particular interest to me is that when we look at a current heat map of permitting activity for the past 30 days, coupled with current active rigs, we clearly see that Oklahoma, particularly the Woodford Shale play in the Anadarko basin, is one of the nation’s bright spots.
In a presentation earlier this year, another STACK devotee, Felix Energy, talked about the performance they have been getting from applying new technology to the play area. 3 things caught my eye in this presentation:
No produced formation water – they’re drilling for hydrocarbons and not having to deal with water disposal (!)
Horizontal redevelopment with modern stimulations has yielded tremendous economic results – New horizontal wells 50x original vertical wells (!)
Proponent of Slick Water proppant, and in 2015 using up to 2000#/ft (!)
The Woodford Shale and Hunton Group and the more recently targeted Springer Shale span from the late Ordovician into the Mississippian in geologic age.
Image Source: Drillinginfo South-Central Oklahoma Basins Play Assessment materials
If we look at the last 90 days of rig counts by county in the Woodford Shale, we see a slight pullback in the clear leader Grady from 16 to 12 rigs, a slight contraction from 8 to 7 in Canadian County, and a nice rally in Blaine County from 3 to 8. The Other STACK County, Kingfisher, is riding in fourth place, having gained a rig over that time period.
Image Source: Drillinginfo Rig Analytics
Looking at that same time period in just SCOOP and STACK counties, and cross referencing the targeted formations, we see a clear preference for the deeper Woodford and Hunton formations.
Image Source: Drillinginfo Rig Analytics
Woodford Shale New Production Capacity
On November 12, Drillinginfo will release its latest DI Index of New Production Capacity (NPC), which couples rig activity with active permits, compares the new wells’ performance with comparable wells, and creates an estimate for the capacity that will be brought online from that well in the next few months. This next image compares the NPC for Woodford Shale counties from October’s activity.
The amount of natural gas capacity coming online from the more easterly Hughes and Pittsburgh Counties is certainly striking, all the more so given that there are only 8 rigs generally running around the two. Just more evidence about how much more efficient the gas producers are getting at their game.
Next, Two of the top Five counties on the chart are Canadian and Kingfisher (and the final top fiver is neighbor Blaine), further reinforcing the current investment (and potential results) of the STACK play. And then, also with respectable numbers, Stephens, Grady, Garvin, and Carter show how the heart of the SCOOP is performing.
While the price of WTI crude oil was in the process of dipping below $44 in March, most operators were tasked with decreasing costs as much as possible. Even with the current recovery hovering near $60, it’s probably not the best time to suggest spending an extra $1 million dollars for more proppant in each well. However an analysis of proppant concentration in the Bakken suggests that this may be a great time to have this discussion.
When planning for how heavy to engineer wells there are a few general scenarios to consider. Should we over-engineer the best acreage or will our best acreage produce enough with moderate engineering? Can we over-engineer the poorer rocks to get them to produce like higher tiered acreage or will this be a waste of money? This study takes a statistical approach to quantifying answers to these questions.
For this analysis we need to start with a geological framework. This will allow us to analyze the effects of proppant within similar geology. The DI Play Assessment for the Bakken provides this geological framework which includes stratigraphic correlations along with structure, thickness, and property maps. This framework is delivered in the DI Transform platform. DI Transform includes multivariate analytics which gives users the ability to analyze effects of engineering parameters within specific geology. Finally, incorporating refined well data from DI Analytics sheds time by allowing the user to start off with clean, aliased data necessary for statistical analysis. DI Analytics is also the source for two other key components in this study, proppant amounts and our graded acreage map.
First let’s take a look at proppant/ft in the North Dakota portion of the Bakken play. Here we see a 0.379 correlation between proppant per foot and initial 12 month oil production. Figure 1: This crossplot compares proppant/ft (X-Axis) to initial 12-month oil production (Y-Axis).
Next, let’s see how proppant concentration has evolved over the course of Bakken development by analyzing proppant/ft versus spud date.
Figure 2: The crossplot on the left shows how much proppant/ft (Y-Axis) has been used over the development of the play by comparing this to spud date (X-Axis). The plot on the right shows this same data filtered on 3 key Bakken operators.
We can see that proppant use has increased significantly since early 2012. The cross-plot on the right shows that one key operator (with purple data points), led this push. We also see two other key operators in red and blue starting to significantly increase proppant concentration.
For this study, let’s break out the samples by their graded acreage. We’ve set up three tiers. These include grades 1-3, grades 4-6, and grades 7-9. A map of this tiered acreage is included below.
Figure 3: Grades 1-3 displayed in red, Grades 4-6 in green, Grades 7-9 in blue. Rigs are also shown.
Now that we’ve broken up the play into three tiers based on the geology, we will analyze proppant in each tier. When looking at the bi-variate cross-plots for each of these three tiers, we can see varying degrees of positive correlations. Tier two acreage has the best correlation with a 0.497 relationship. Tier one is second with 0.290. Tier three has just a slight 0.0596 relationship.
Figure 4: These graphs show proppant/ft (X-Axis) versus initial 12 month oil (Y-Axis). The top left graph is tier 1, the top right is tier 2, the bottom left is tier 3, and the bottom right is all tiers.
The increase in oil production for the top two tiers of Bakken acreage is very encouraging, but not so encouraging for the bottom tier acreage. If we follow the correlation line, we gain approximately 50k barrels by increasing from 400 lbs/ft of proppant to 900 lbs/ft of proppant in tier 1 acreage. In tier two acreage we gain approximately 70k barrels for the same increase. For a 10,000 ft lateral, common in the Bakken, an increase of 500 lbs of standard proppant would add approximately $1 million to the well. This is based on an assumption of 20 cents/lb for standard proppant.
With WTI prices around $59 and assuming a return of approximately $40 per barrel after royalties and other fees, we would increase our return by approximately $1 million per well in the first year by increasing the proppant from 400 lbs/ft to 900 lbs/ft in tier 1 acreage. In tier 2, this net increase is approximately $1.8 million per well. Increasing the proppant in tier 3 acreage would result in a loss of around $850k per well.
For an even more granular look, we analyzed proppant/ft within a multi-variate statistical model. This will normalize the effects of horizontal length along with key geological attributes so that we can specifically focus on proppant/ft within the model. Using this analysis, the upside of additional proppant/ft is even greater. Tier 1 now reveals an increase of approximately 70k barrels, or an increased ROI of approximately $1.8 million within the first year. For tier 2, these values increase to 100k bbls and $3 million. We still show a large loss when trying to pump more proppant into the lowest grade acreage. These models are seen in the next few images. Figure 5: Multi-variate model for tier 1. The graph on the left shows the overall model. The graph on the right shows the effect of proppant/ft on the model if we fix all other values to their averages within this sample size.
Figure 6: Multi-variate model for tier 2. The graph on the left shows the overall model. The graph on the right shows the effect of proppant/ft on the model if we fix all other values to their averages within this sample size. Figure 7: Multi-variate model for tier 3. The graph on the left shows the overall model. The graph on the right shows the effect of proppant/ft on the model if we fix all other values to their averages within this sample size.
Here are a few takeaways from this study. Stepping up on proppant concentration in quality acreage appears to provide outstanding returns, but over-engineering the bottom tier acreage looks like a waste of sand. Another interesting observation is that from a statistical perspective we have yet to see a turnover where increased proppant concentration no longer matters in the quality acreage. There still looks to be better ROI with more and more proppant in the top two tiers of acreage. Eventually these plots will plateau at the top indicating diminishing returns, but this hasn’t happened yet.
For a more detailed look this analysis could quickly be run in each grade of acreage or around your specific holdings. It could also be run on other completions metrics that you feel are key contributors. It’s more important than ever to not think it terms of strictly cutting costs, but rather in terms of optimizing your completions for ROI.
So maybe it’s time to march into your boss’s office and request that you double down on proppant in the Bakken. Tell him or her that it will only cost an additional $1 million per well. If you can present your analysis before you’re placed in a strait jacket then you might just be a hero.
I recently wrote a blog post on the Smoky Hill Member of the Niobrara formation. While researching I was looking at some paleo maps, and thought it would be a neat idea to create a visual representation that shows the United States throughout geologic time. You can find the animation below. While watching you will notice that I have outlined the location of some unconventional plays at their time of deposition.
Oil generally forms in shallow marine environments where carbon rich organic matter can accumulate. Sometimes it is difficult to imagine a shallow marine environment existing in parts of the country far from the ocean, such as the Niobrara in Colorado or the Bakken in North Dakota. It is important to remember, however, that the landscape of the United States has changed dramatically throughout geologic history.
Due to the push and pull of plate tectonics, the North American continent has moved, combined, and separated with other landmasses. One of these landmasses was Pangea, a supercontinent that existed in the late Paleozoic and Early Mesozoic approximately 200 to 300 million years ago.
Unlike today, where most of the landmass resides in the Northern Hemisphere, Pangea was located primarily in the Southern Hemisphere. This is a great example of how much the continents have changed throughout time.
As the geography of the United States has changed, the places that are likely to produce oil in the future have changed as well. Using paleo maps from the DI 2.0 application we can visualize the continental United States beginning with the Cambrian (570 Million years ago) to the Holocene (the present).
Petroleum geologists can use maps such as these to better understand the depositional environments of the past which can be helpful in finding new places to drill for oil. A lot of things can occur over millions of years, so in addition to the location of oil plays I have noted other interesting geologic events and fossils present at different times in the video.
Well for one thing it has nothing to do with smoke at all. The Smoky Hill Member is a distinct section of fossil containing rock within an oil and gas play known as the Niobrara formation.
The Niobrara, which is located about 3,000 feet beneath the surface in North East Colorado and extends into Wyoming, Nebraska, and Kansas, is broken into two members, The Smoky Hill Member and the Fort Hays Limestone. This is not an even close to a fair split. The Smoky Hill Member makes up the majority of the Niobrara and can be further divided into benches A, B, and C. The Niobrara formed during the Late Cretaceous in a marine environment. It is an organically rich carbonate rock composed of interbedded shales and chalks.
The Smoky Hill Member contains some spectacular fossils which can be found in outcrops in Nebraska and Kansas. Some of these include; marine reptiles, flying reptiles, large boney fish, turtles, ammonites, and many more. Source: http://www.oceansofkansas.com/Plesiosaurs/plio-lrg.jpg
Here is an image of one specimen called Dolichorhynchops Osborni, which is located in the University Of Kansas Museum Of Natural History. This specimen was originally found by a teenager named George F. Sternberg around 1900; it was located in Logan county Kansas in the upper section of the Smoky Hill Member.
During the Late Cretaceous
The Niobrara formed during the Late Cretaceous, 82-87 million years ago. The geography of The United States was completely different at that time. North America was split into two landmasses by the Western Interior Seaway. This seaway extended from the Arctic Ocean to the Gulf of Mexico and was more than 930 miles wide at its max.
Western Interior Seaway during the Cretaceous, image is from DI 2.0 Paleo maps
There was a high sea level at this time. There are many factors that can play a role in sea level rise; in the Cretaceous it was due to fast seafloor spreading rates in the Atlantic Ocean. Fast sea floor spreading changed the topography of the ocean floor, making it shallower. This displaced large amounts of water that migrated upward onto the continents in low topographic areas, which led to a marine transgression and ultimately the formation of the Western Interior Sea Way. There was a lot of carbonate deposition at this time suggesting that the climate was much warmer and more humid than today. This caused the temperature differential in the ocean between the poles and the equator to be mild which slowed ocean currents. Without the ocean currents there were times of stagnant, anoxic zones resulting in shale deposits. This is how the interbedded carbonate and shales of the Smoky Hill Member formed.
Why Are We Interested in the Niobrara?
Besides digging for fossils the Smoky Hill Member and the Niobrara are known for their oil production. To see evidence of this we can look at a map to see how many people are drilling in the area and a heat map to see the concentration of permitting.
Image from DI 2.0
We can see that the Niobrara, outlined in orange, is located in the north eastern section of Colorado and within the former western interior seaway. Looking closer we can see that operators are currently drilling in the area (each red dot is a drilling rig!), and there has been a lot of permit activity over the last 90 days. This information shows evidence that the Niobrara play is one of the hot spots to drill for oil in United States.
DI Geology Clearing the Smoke
Drillinginfo’s geology team is currently working on modeling the Niobrara play. They are focusing on the Wattenburg field and then extending to the north east. The Geology team has over 6,000 digital well logs from the area! The logs are loaded into Transform (DI’s own predictive analytics platform) that allows the geologists to pick surface tops, normalize the logs, and create a variety of maps to show the complex structure of the Niobrara and its benches. This information and resulting insights will soon become available to our clients.
Let’s take a closer look at a type log. The geology team has divided each bench into 4 separate suface tops with the first top corresponding to a maximum flooding surface (MFS), a time of high sea level. The logs below represent a type log for the Niobrara. The curve to the left is a gamma ray log with a color fill, the log to the right displays a gamma ray and resistivity.
Now let’s put these wells together and look at cross sections throughout the Niobrara.
Here is a well-to-well cross section that is flattened on the B bench base. The B bench base was picked at the end of the resistivity signature marking the end of the producing zone for the B Bench.
You can see that there are thicker shale units towards the left side of the cross section (the shale units are represented by the dark brown color). The Bright section below the middle represents the Fort Hays Limestone. The wells that seem to be offset represent missing section which suggests the presence of faults.
Where is the geology team working next?
We have identified 27 unconventional plays in the United States, and the DI Geology team is working on interpreting the stratigraphy to create an earth model that can potentially connect all of these plays. Once we finish modelling the Niobrara, we will be moving onto the next play and continue developing quality products for our clients.
There comes a time in every geologist’s life where he is forced to look at a bunch of well logs and make some sense of them and the surrounding geology. (OK, that time usually comes fairly early in their career – maybe the first day). No matter if you are looking for structural traps, stratigraphic traps or looking at one of the unconventional shale plays it all starts out looking at a well log.
The Black and White Past
Interpreting information from wells logs has gotten both easier and harder at the same time. I remember those days when you use to take a bunch of paper logs, hang them on the wall and tried to correlate the various formations. The hardest thing was to get all the logs copied at the same scale (2 inch for regional work, 5 inch for field or development work). Then there was normalizing the logs to account for different tools and different contractors. My favorite (actually least favorite) was the SP shift that always seemed to happen right in the middle of the zone I was interested in.
Then there were the tools of the trade, to mark your formations. I recall someone expensing colored elastic string and having accounting deny the expense as something that was not an approved office expense. He turned around and resubmitted it as “elasticized stratigraphic correlation markers” and it was approved immediately – apparently accounting knew what that was. Paper logs had lots of holes at the top from the countless times it had been pinned to the wall (when you traded logs with someone and the logs you got didn’t have pin holes in them, you knew you were getting great stuff).
There were some good things also – there was only a handful of different types of logs, there weren’t that many wells and splicing multiple runs together involved a fold and scotch tape. Ah, the good old days.
It’s 2014 – Things Sure Have Changed(?)
Today I have three 29 inch LED monitors that stretch across my desk and show more wells than I can even imagine (OK, I just lied about the 3 monitors. However, I did have it on my Christmas wish list this year. Apparently in the naughty/nice decision, things went badly for me and I continue to use my two 19 inch monitors but I harbor no ill will SANTA!).
The reality today, the more screen real estate you have the better off you are going to be (just like wall space in the old days). Monitors are better, bigger and cheaper. I have seen some office configurations that are amazing and allow construction of sections that we could only put up in a conference room if we were forced to go back and use paper.
Logs today are actually a lot more complex for the average interpreter. Who invented all these logs? Petrophysicists are giving the geophysicists a run for their money on who can consume the most disk space. Logs that view 360 degrees of the borehole for each depth sample taken give an amazing view of the rocks that the interpreter has never had before. There are also more log types. Thankfully packages like Transform Essential have simple ways to alias various types of curves so that all the Gamma Ray curves, for example, all end up together so different names with the same log type isn’t such a big deal. Transform is even going to do your log normalization for you – look for it in a release coming soon.
Splicing multiple runs back together might be something you never need to worry about. LAS logs that Drillinginfo has processed in the past 4 years are all spliced together for you already. So you might not actually have this problem.
Remember “elasticized correlation marker”, well those days are gone. Geophysicists have an auto-picker for seismic, so now the geologist has an auto-picker for well logs. The formation top picker allows the geologist to make a single pick and the system will make the equivalent pick in the surrounding well logs. You can even bracket picks. Surfaces that are harder to pick can be focused above, below or between 2 formations that have already been picked.
The trick to using a system like this is to have the system identify the top of easily identified regional markers then go back and have the system pick more subtle markers between the regional picks. What took days/weeks now takes minutes. Maps can then be easily created allowing the geologist to quickly find any problems that might have occurred. This allows the geologist to be more of an editor instead of being the person that does the picking.
I confess, I hated picking tops. The first few days were fun, the second week was ok but week 15 made me wish for the days when some machine would do this for me. The fun part for me was looking at the logs and figuring out the EOD (environment of deposition), how the rocks were deposited and then what happened to them – was porosity preserved or was the porosity secondary? Were the rocks tilted? Where did the hydrocarbons come from and how were they trapped? That is the fun part and that is the part that still requires a geologist to piece together the geological puzzle from the logs, cuttings, cores or any other piece of data that we can get from the wells and seismic.
No more spending mindless days/weeks picking tops, welcome to the good old days.
Every once in a while I like to pass along a secret on how to get some added feature that you might not know about. This one has to do with free log data. For those of you that are Pro customers, you have it made. You can look at any well / LAS data in Drillinginfo’s huge library. However, for those that are not Pro customers, there is a way to view a lot of the LAS Gamma Ray curves in our library. Click on the 2.0 button and view all the wells. You can then window the map as you would in any web map. When you click on the + just to the left of the layers menu, some of the wells will go away leaving only the wells that have LAS curves. Click on any well and a tiny cross section will appear showing the Gamma Ray log for that well just below the map window. You can’t export it but you can take a look at it.
When I started working in geology, my wife and I developed a standing joke.
Instead of asking me about my day, she would ask, “So did you solve the US energy crisis today?”
Taking things to maximum absurdity, I would often leave the house in the morning saying, “Well, I’m off to solve the energy crisis.”
Obviously no single person could solve the US energy crisis. However, it does raise the question – how can someone maximize his or her impact on the oil industry?
In the Beginning
I spent my early career in geology. I drilled a few oil and gas wells (OK, I might have drilled a dry hole … or two). The impact I made on the US domestic energy supply was probably negligible. Working as a geologist, however, was lots of fun. It’s like solving a giant underground puzzle, where the pieces moved through time. Those movements affected lots of things, like porosity, permeability, source, structure and dozens of other variables. You have to be smart, clever and creative all at the same time.
When everything works perfectly, you get to sit back and quietly say, “Nailed it.” However, the drill bit is the ultimate reality and mother earth is constantly changing the rules. Just when you think you understand a reservoir, the drill bit hands you something completely unexpected.
Oil Industry Geology Today
Now most geologists work in teams. The larger the company, the more likely you are paired up with people from other disciplines. I maintain that even if you are a one-man company, you have a massive team around you helping support whatever decisions you make.
There are people that scan logs to provide raster images or digitize them to provide LAS curves. Teams of people provide well, production and leased data. People also design software so you can easily make more accurate decisions quickly – that’s where I come in.
But Who Can Really Move the Needle?
Let’s talk for a minute about people that have made a real impact in the industries they love. We all know Alexander Bell, Thomas Edison and more modern computer icons like Bill Gates, Steve Jobs and Mark Zuckerberg. However, have you heard of Bill Joy, Linus Torvalds or Tim Patterson?
Tim Paterson was the original author of MS-DOS. Without DOS, you could argue there never would have been a personal computer revolution in the 80’s. Everything Microsoft produced for many years relied on DOS as the backbone, including Windows.
Linus Torvalds is the creator of the Linux kernel. Today, the Linux kernel runs almost every super computer in the world. It also runs phones, tablets, PC’s and a host of appliances.
In my house, the Linux kernel runs my TV, DVD player, stereo, phone, tablet and my desktop computer. There is also a very good chance it will run in the next automobile I drive.
My point is you don’t have to be a corporate entrepreneur to make a huge impact.
When I left the world of drilling wells as a geologist to go into software, my friends advised me not to leave. “The industry needs geologists like you and once you leave you will never be able to come back,” they told me.
The reality is I never left.
The software I helped design and deliver as part of a team is being used all over the world making discoveries I will probably never know about. The geologist working on those prospects will never know that my team and expertise was part of their team in finding the oil or gas.
That is OK.
I don’t give much thought to who invented the operating system when I Google something on my phone. I’m simply thankful that someone had the vision to invent it so it is there when I need it.
Teamwork Makes the Dream Work
There are many ways to change the oil industry when you’re a geologist. One way is to spend years on the team that will find that one big field offshore. Another is to be part of a team that provides the tools, data and expertise to tens of thousands of people looking for oil all across the globe.
And even if you are not a geologist, you can change the oil industry. My team at Drillinginfo is made up of geologists, engineers, landmen and dozens of other experts. Without them, I couldn’t do what I love. We are working on solving conventional problems and we’re the leader in providing data, tools and analytics to help solve unconventional problems.
Hey wait, did I just say “unconventional?” Maybe I am solving the US energy crisis after all!
What’s your oil and gas industry story? Did you start out in the patch and eventually work your way to the desk, like myself – or vice versa? Please leave a comment below.
And if you’re a geologist or anyone else in the industry looking to make a career transition, you can search our current openings here. If experience is any indication, you would probably make a fantastic addition to the Drillinginfo Family.