PART 1 of 3—OVERVIEW
In the last 36 months, 34,070 horizontal wells have been completed in the U.S. This represents about 12% of all horizontal wells drilled, and since the last three years have seen a big uptick in both activity and technology improvement in unconventional play development, I thought it was a good time to dig into geosteering data to get some perspective on this critical piece of the unconventional puzzle.
Of the horizontals completed in the last three years, nearly 14,000 have been analyzed in our Play Assessments application for characteristics, such as percentage of well bore in landing zone, toe in landing zone, and footage in landing zone.
How good of a job have we done getting our horizontals into their targeted landing zones to maximize the productive potential of our unconventional resource play acreage?
Using our highly quality controlled DI Play Assessments data, we can start taking a look at these 14,000 wells to see where operators landed their wells.
Since wells with a relatively high percentage of out-of-zone drilling within targeted landing zones will negatively affect play economics, I thought I’d look at wells, by basin, in Play Assessments with 25% or more of lateral length out of zone. The graph below shows the percentage (displayed logarithmically) of wells, by basin, that had less than 75% of their wellbore positioned in the intended landing zone.
Note that the DJ, Gulf Coast, and Williston were the most likely basins to see wells out of zone (DJ 35%, Gulf Coast 13%, Williston 21%).
In contrast, the basins that showed the highest percentages of wells 90% or greater in zone were the Central Basin Platform at 94%, Mid-Continent at 91%, and Midland Basin at 90%. What accounts for the differences?
Operators in the three Permian sub basins—Delaware, Central Basin Platform, and Midland—are doing a great job of landing their wells in zone and keeping them there.
But what’s going on the Williston and DJ in particular?
These are the most targeted landing zones by basin (source: DI Play Assessments).
For the 23 operators that have completed any wells in the last three years with at least 25% of the wellbore out of Middle Bakken landing zone, nearly one quarter of them account for almost 45% of the out-of-landing-zone wells.
Since the percentage of total wells completed with more than 25% of lateral out of zone in the Middle Bakken in the last three years is about 16%, is this operator dependent or geologically driven (high faulting, rapid lithologic changes, challenges of staying in zone in high dip areas)?
Since the out-of-zone wells are not concentrated in one part of the basin, this implies that geology, faulting, or steep dip complications are not the drivers of out-of-zone performance.
Most of the large operators have done a good to excellent job of keeping their wellbores in their landing zones.
If we look in DI Play Assessments at the 10 operators in the DJ that account for 93% of the wells landed in the Niobrara B, their in-zone landing performance is also quite variable.
Plotting these on a map also shows spatial variability in the position of these wells, again implying that the out-of-zone performance in the DJ is most likely operator driven and not tied to geologic complexity.
In Part 2, I’ll look at identifying the most problematical landing zones.
Please send me an email at firstname.lastname@example.org if you have any observations on or comments about geosteering challenges.
If you’re like me, 95% of your attention is focused on U.S. oil & gas. Probably 95% of that 95% concerns unconventional plays, metrics, news, and activity.
What’s happening in the rest of the world?
We all know that unconventional resource development is increasing the supply of oil and natural gas produced in the U.S. Restatements of recoverable reserves to the upside in the Permian and other play areas paint a picture of continued supply to meet demand.
However, the U.S. Energy Information Administration (EIA) predicts the U.S. oil supply will level out in 2023.
World supply is projected to begin declining in 2022, as shown in the slide below from this Seeking Alpha article.
What about demand?
Wall Street has assumed that current worldwide economic growth models tied to weakness in the Chinese economy will, at some point, disappear and demand growth for liquid hydrocarbons will resume.
Bank of America Merrill Lynch doesn’t see it this way. An Oilprice.com article (https://oilprice.com/Energy/Energy-General/Bank-Of-America-Oil-Demand-Growth-To-Hit-Zero-Within-A-Decade.html) states:
By 2030, oil demand could hit a peak and then enter decline, according to a new report.
For the next decade or so, oil demand should continue to grow, although at a slower and slower rate. According to Bank of America Merrill Lynch, the annual increase in global oil consumption slows dramatically in the years ahead. By 2024, demand growth halves, falling to just 0.6 million barrels per day (mb/d), down from 1.2 mb/d this year.
But by 2030, demand growth zeros out as consumption hits a permanent peak, before falling at a relatively rapid rate thereafter.
The article ties the projected demand drop to greater market share of electric vehicles, reducing demand for hydrocarbon liquids. However, aging demographics and student debt load in the U.S. also affect demand.
What if these projections of reduced demand are too aggressive? What if highly populated, non-first world countries simply cannot build the electricity-generating capacity and distribution infrastructure fast enough to meet their citizens’ mobility needs?
We then need to re-ask the question: where does new supply come from?
The number of wells drilled and/or producing in the U.S. and Canada is five to seven times the number of wells worldwide.
Every year since 2013, countries around the world have engaged in transactions that conveyed seven to 16 times the amount of acreage in the Permian Basin. In 2014, more than 852 million acres traded hands.
The graph below shows the trends since 2013.
Some of the blocks are huge. For example, Congo’s “Block 02” is about 12 million acres in size.
This is a big, big problem that impedes the efficient and timely evaluation of world reserves.
The lack of support infrastructure outside the U.S. makes international exploration expensive. To offset this risk exploration, licenses are often granted for 10-year terms contingent on the performance of a work program (collect new seismic, drill some wells) and relinquishment of a sizable fraction of awarded acreage after five years.
This means that huge areas of potentially productive basins/plays are being evaluated by ONE operator — and those evaluations take a long, long time. One would likely find 100 plus operators working this amount of acreage if it were in the Permian. Each of them would drill wells, run logs, perforate zones of interest, and rapidly expand the knowledge base about the basin, trap types, and economic viability.
Political stability and a well-functioning legal system that fairly administers the law are key requirements for companies that wish to invest in the world’s oil & gas potential.
Many countries must come to terms with fiscal regime structures that are punitive.
For a quick, simplified perspective look at this chart:
The dotted red line represents 25% — the current, generally accepted upper limit on royalty in the U.S.
With very few exceptions, most countries are taking 50% or more of the produced hydrocarbons from these concessions.
Throw in the lack of infrastructure — roads, pipelines, power, drilling rigs, and crews — and the obstacles to attracting non-domestic capital for E&P development get bigger and bigger.
However, capital investment by forward-looking third-party sovereign nations may be the key to changing this outlook.
For example, the map below shows Chinese (government and private) investment in Africa.
More than 50% of the promised direct investment will be in critical wealth-building sectors — oil & gas, power, and transportation.
The Democratic Republic of Congo has shown a willingness to jumpstart private direct investment by creating special economic zones that promise favorable regulatory oversight and more favorable taxing policies.
Economic zones that emphasize tax breaks for the oilfield service sector could lead to critical mass staging of rigs, open hole logging services, pipe, and other critical infrastructure materials. This critical mass might lead to lower project costs and faster project evaluation.
If other countries would consider following Congo’s lead, the path to a better understanding of world recoverable reserves would be clear.
What are your thoughts on the ability of the international oil & gas business to meet future demand spikes?
How can countries create evaluation programs that quickly identify reserve potential across big licenses?
Let me know at email@example.com.
What do the European Organization of Nuclear Research (CERN), the PGA Tour, deep sea divers, partiers, and ravers have in common?
Atomic No. 2 — aka Helium.
CERN uses helium to cool the super magnets keeping all those subatomic particles moving in the right direction at the Large Hadron Collider.
Golf aficionados have always appreciated the incredible resolution of cameras at 1,000 feet, peering down on the greens and fairways during iconic tournaments, which is made possible by element No. 2.
Divers have helium in their breathing mix to lessen the risk of the bends and oxygen toxicity.
Finally, we all get a great laugh at a party when a friend’s deep voice is turned into a Mickey Mouse squeak after inhaling helium.
Helium was added to both the U.S. and European Union critical minerals lists in 2018. Since the U.S. Bureau of Land Management (BLM) is required by the Helium Stewardship Act to quit operating the Federal Helium system in 2021, the private markets and international players have begun to step up and fill the void.
To understand where the industry sees itself, I recommend reading this gasworld article about the Global Helium Summit 2018: https://www.gasworld.com/global-helium-summit-2018-closes/2015512.article.
Helium becomes more than just an esoteric curiosity when its economics are considered. The graph below shows the tightening of helium supply in the U.S.
Reflecting the supply squeeze, prices at the most recent BLM auction (Aug. 31, 2018) ranged from $233/mcf to $337/mcf — roughly 78 to 100 times the price of quality natural gas.
Where can we find it?
The United States Geological Survey (USGS) has a database on helium concentrations reported in a sample of wells (
Here’s the location of wells reporting mol% concentrations of 2% or more (note that not all wells with measurable helium are in the USGS database):
The following graph shows mol% concentration as a function of reservoir name.
The top three by count in this sample are: Arbuckle (38), Keys/Keyes (141), and Morrow (38).
Other sources cite high concentrations in the Coconino Sandstone (Arizona), McKracken Sandstone (Arizona), and Lyons Sandstone (Colorado).
The USGS data may have guided Desert Mountain Energy in their recently announced transaction (Jan. 15, 2019) to buy 884 acres from Seminole Production Partners in Seminole County, Oklahoma, to pursue the helium potential from the underlying Gilcrease reservoir (https://www.gasworld.com/desert-mountain-energy-acquires-oklahoma-project/2016315.article).
If you roll areas of known helium production — LaBarge, Riley Ridge, and Cliffside Field storage — into the previous maps of high helium concentration, it’s clear there are several basins and provinces that could be considered helium “rich” in the lower 48.
Per John Gluyas’ great article in the February 2019 issue of AAPG Explorer, the minimal exploration constraints for concentrations of helium are:
- Old granitic basement to source He4 (the usable isotope)
- Recent compression heating and compression of the “source” rock to release the helium
- Transport of helium with natural gas, usually nitrogen
- Migration into a “trap”
- Degassing at shallow depths or entrapment in natural gas reservoirs
How aware are operators, especially in horizontal unconventional resource plays, of the helium concentrations (read=value) in their natural gas stream?
Is helium production explicitly covered in modern mineral lease agreements?
Is there enough helium going into the gathering systems of major unconventional plays to consider building the infrastructure to extract helium to supply a tightening market?
Has helium bypassed the unconventional reservoirs and migrated uphole to shallower, less pressured reservoirs?
As always, I’d love to hear if you or your company is actively accounting for potential helium-derived additions to your bottom line.
Please send your thoughts to me at firstname.lastname@example.org.
I’ve received several positive responses from folks about my Feb. 27 article, “Conventional in Unconventional—Where’s The Love?” The most compelling was from Endeavor Natural Gas’ Thad Bay who provided me the following presentation on Endeavor’s recognition of shallower opportunity in the Upper Cretaceous of South Texas. It’s a good read and hopefully provides useful information to operators in these play areas.
Endeavor Natural Gas Presentation