Is the Permian Stalling?

Is the Permian Stalling?

Recent commentaries on the magic of the Permian miracle have had some dark musings about how the Permian is beginning to “stall.”

Given all the back and forth in the investment community about “capital discipline” and output growing supply to the detriment of pricing, I thought I’d take a brief look at Estimated Ultimate Recovery (EUR) growth in the Delaware Basin to read the tea leaves.

On a very gross level, median oil EUR across all reservoirs has improved year-over-year as shown below (EUR binned by year of first production, EUR data from Wellcast).

A look at all wells identified by landing zones, with enough months of production to support reasonable EUR calculations over time, looks like this:

The trend is pretty clear—by and large, well EURs have improved over time, although it looks as over the past 12-18 months the uptrend in improvements has moderated. This is probably due to downspacing and the potentially negative effects of parent-child well interference.

Note however, that starting in early 2016 the number of wells that significantly outperformed the median values increased (outlined in red above). This “breakout” of superior performance may be a harbinger of better returns to come—unless the cumulative production values are actually stacked well reporting.

The distribution of wells binned by EUR greater than 500,000 and 1 million Bbl shows year-over-year improvement, but with less acceleration year-over-year for 2017-2018.

If we look at a graph of EUR distributions by reservoir, we get what you see below:

This shows that for the landing zone assignments in Wellcast (Bone Spring Second Sand, etc.) there are relatively smooth distributions of EUR values for all mapped reservoirs, although some reservoirs have been preferentially targeted by operators. For example, the Wolfcamp A Lower has been the most preferred drilling target.

The story of improving EURs over time is generally true at the reservoir level.

Graphing sample size, number, and percentage of wells with greater than 500,000 BO EUR and greater than 1 million BO EUR, it’s clear that some reservoirs deserve the higher drilling densities they’ve seen. The percentage of wells with EURs greater than 500,000 Bbl or even 1 million Bbl is significant. The Wolfcamp Lower A saw 54% of wells with oil EURs of 500,000 Bbls or better, and 15% of well with oil EUR of 1 million Bbl or more.

We can focus on the Bone Spring Second Sand and the Wolfcamp A Lower for a bit of added insight.

Over time, Bone Spring Second Sand EURs have steadily improved, although moving into 2019 there’s a hint of a drop off.

As might be expected, early engineering practices improved over time to deliver growing EUR valuations. Starting around the end of 2016 into early 2017 we began to see wells with exceptional outlier EUR values (circled in pink).

We see the same behavior in the Wolfcamp A Lower.

I attempted to see if there was a generic explanation for the exceptional EUR outliers hidden within the engineering data—lateral length vs. total proppant vs. total fluid, etc.

Both the Bone Spring Second Sand and Wolfcamp A Lower show year-over-year increases in the lateral length drilled, the amount of proppant, and the amount of fluid deployed in completions.

Bone Spring Second Sand EUR as a function of lateral length shows that two lengths—5,500 to 7,000 feet and 8,500 to 9,500 feet, are likely to limit the number of wells with EUR values greater than 700,000 Bbl. However, there’s clear trend toward higher EUR with increased lateral length.

Wolfcamp A Lower EURs also show an increase of EUR with lateral length, but the trend is more subdued, with excellent “outlier” EUR values (2 MMBBL or higher) occurring over the range of 6,000 to 10,000 feet. Laterals longer than 13,000 feet generally yield EUR values that are closer to the median reservoir value.

There’s clearly a positive correlation for increased EUR with both total proppant and total fluid in the Bone Spring Second Sand.

However, there is less of a correlation between total proppant and EUR for the Wolfcamp A Lower.

This is probably best explained by stratigraphy—the Bone Spring Second Sand is encased between two carbonate benches that inhibit frac jobs from exiting the Bone Spring Second Sand. This concentrates all the frac job power within the target.

The Wolfcamp A Lower is more than 500 feet thick, is interbedded, and is not bounded by focusing carbonate benches above it and below it, meaning frac jobs are a bit more likely to disperse their energy away from the target being drilled.

Until the spacing “secret sauce” is better understood, accounting for offset interference and variables in engineering and completion practices (and hopefully, geology) to define variables with better than .6r correlation coefficients with EUR will be a challenge.

However, given the steady increase of EUR values—both basin-wide and by reservoir, as well as hints that exceptional outlier values may become the next EUR “norm,” it’s premature to claim that Permian output is declining.

Have a perspective on EUR values?

Please send me a message at

(Note: EUR data and landing zone play identification names were obtained from the Enverus Drillinginfo Wellcast product. Only wells with six months or more of production history were included in the analysis.)



The oil and gas industry is currently grappling with fears of both oversupply and weakened demand.

Demand side weakness is tied to tariffs, strength of the dollar, and a slow but apparently inexorable increase of market share for renewables and green alternatives to the traditional hydrocarbon supply of needed global BTUs.

Increasing supplies of power generated by wind and solar are finding their way into the nation’s power grid, and utility scale storage systems, such as Tesla’s Megapack, upgrade the reliability of power delivery from these sources.


Utilities around the country are looking to slow or cease deployment of natural gas fired peaker plants (plants that fire up when demand use is projected to peak) in favor of lean alternatives.

For example, Glendale, California, decided to drop a planned $500 million gas peaker project in favor of cleaner, greener alternatives.

On-demand battery storage at scale should spur the deployment of charging stations for electric vehicles, therefore reducing demand for gasoline or diesel.

Trying to project energy demand growth is a murky prospect at best, but the following sources make these notable claims:


Currently, financial analysts focus on the output and volume adds attributable to unconventional plays like the Utica, Haynesville, Bakken, and Eagle Ford.

However, little attention has been paid to reserves in the rest of the world.

The title of this piece is “U.S./World=6.” It’s pretty simple—about six times as many wells have been drilled in the U.S. than have been drilled in the rest of the world.

There are many reasons for this:

  • Stable democracy governed by effective rule of law
  • Individual ownership of mineral assets vs government/sovereign ownership
  • Sufficient transportation and infrastructure options
  • A rich history of multiple operators (i.e. drilling experiments) that advance the knowledge base of all participants improving risk profiles
  • Access to investment lending

So, what would happen if other countries started migrating their oil and gas assets toward a U.S. model?

It’s hard to imagine they would devolve mineral ownership to the population at large, but they might begin to think about awarding smaller blocks with more favorable terms to spur investment.

Think about this. There’s a block in Algeria—Tindouf Centre (Tindouf Basins)—that’s roughly 40% the size of the entire Permian. Twelve wells have been drilled in the basin—a drilling density of one well every 2,800 square miles. In contrast, the drilling density in the Permian is approximately one well every ¼ square mile.

Consider that there’s a block controlled by a state oil monopoly that’s approximately one third the size of the Permian. Since the contract was awarded earlier this decade, exactly one well has been drilled.


This is ludicrous.

Governments around the world must wake up and realize the only way to unlock their mineral wealth is to foster competition by providing attractive deal terms and moderately secure infrastructure—at the minimum, decent roads and hopefully some pipeline or rail access to transshipment points.

This is urgently true for countries whose prospectivity is considered questionable or whose development programs are in their infancy.

And … they need to do it quickly. If projections of energy demand are roughly on target, the window for oil demand will be shrinking. If both BP and DNV-GL are correct, oil demand will plateau in 2030. For countries with reserves that are oil rich and natural gas poor, they’ve got scant time to reconfigure their fiscal regimes to quickly attract drilling CAPEX to find and develop their resource base during a time when demand pressures ease and pricing gets soft.

Look to Argentina, where the process of identifying Vaca Muerte sweet spots and exploiting them is underway as endorsed by ConocoPhillips’ recent acquisition of interests in Wintershall’s operated Aguada Federal and Bandurria Norte block.

Set the right conditions, give operators a decent shot at safe, secure, and profitable operations, and—unlike the unnamed state oil monopoly that’s drilled one well in an acreage package one-third the size of the Permian, you get this kind of operator buy-in.


Or look to one of the world’s most controlled economies—China. The Chinese government has recognized that control of the nation’s oil and gas mineral potential must be, at least in part, de-coupled from the major NOCs and allow direct foreign investment to jumpstart technological and capital investment in Chinese basins that will supply the world’s largest population.

Projects such as the East African Crude Oil Pipeline (, with an estimated delivery rate of 216,000 BOPD, and even the Trans-Saharan gas pipeline (length approx. 2,700 miles—Nigeria to Algeria), and the Trans Africa Pipeline—(nearly 5,000 miles in length delivering fresh water to nearly 30 million people—to be supplied by solar-powered desalination plants), show that countries recognize the need for and can seemingly cooperate on a regional basis to build the infrastructure that supports the oil and gas exploration and development cycle.




Providing tax-free or tax-incentive zones so that service companies can concentrate enough material and personnel in non-hub areas to serve a growing exploration and development effort could significantly reduce CAPEX costs in international plays and perhaps entice nimble, well-managed, well-funded, non-major independents to explore.

Eliminating egregious upfront bonus payments and instead biasing contract awards to work programs would be a useful way to get money turning to the right as opposed to sitting idle in a central bank.
Reversionary changes to more punitive fiscal regimes—for example, Australia’s revamping of its Resource Rent Tax, Romania’s negative legislation aimed at offshore gas development, and Guyana’s balancing of terms now that world-class reserves have been identified, may drive the exploration community away at precisely the time they need to be recruited.

If governments can creatively re-think how they attract and spur oil and gas economic development, worldwide supply numbers will dwarf what we currently estimate as our worldwide recoverable hydrocarbon resource base.

Have ideas on how foreign governments can ignite exploration activity in their countries? Please email me at

The Rewards of Staying in Zone?—Geosteering Part III

The Rewards of Staying in Zone?—Geosteering Part III

The industry spends a fair bit of money on geosteering—the process of matching logging-while-drilling data to open-hole log data to ensure that the wellbore is drilling through the most productive rock.

It can be a nerve-wracking process—I know because I did some geosteering on Austin Chalk wells around Dilley, Texas, in the early 90s, mostly by sample descriptions. The technology for doing what we do today was rudimentary, novel, and raw.

Today’s operators can, by-and-large, trust their geosteering contractors or in-house staff to keep them pretty much in their defined target or landing zone, and the geosteering mavens routinely deliver great results.
I’ve taken it as an article of faith that the more the wellbore is in zone, the better the well will be.
However, now that I’ve looked at a fair bit of data, I’m not so sure that’s true.

I looked in DI Play Assessments at wells in the Delaware Basin with a landing zone = Wolfcamp A XY.

There doesn’t seem to be a clustering of out-of-zone wells. Instead they are spatially distributed in the same manner of wells that have higher in-zone percentages.

With the help of our geology team, I got this cross section of the Wolfcamp A XY landing zone. The orange line is the top of the Wolfcamp A XY, the blue marker is the top of the Lower Wolfcamp A.

Note that the section gets shalier as you move from north to south, and the section thins by about 90’.
The map below generally confirms the trend and shows that both out-of-zone wells and in-zone wells are generally targeting the same lithologies.

However, it’s very hard to see meaningful differences in well performance as measured by Peak BOE. The map below compares Peak BOE for wells with less than 5% of wellbore in zone to wells with greater than 75% of wellbore in zone.

Graphing BOE by % in zone shows no meaningful difference in median First 12 months BOE—139,000 First 12 months BOE for less than 75% in zone versus 143,000 First 12 months BOE for more than 75% in zone.

Bulk correlating log metrics like density or neutron porosities doesn’t yield a great correlation with production performance.

There’s little correlation between gross perforated interval and First 12 months BOE.

There is, however, what looks to be a good correlation between lateral length and First 12 months BOE.

So, if your company man calls in and says the geosteering job didn’t stay in zone as much as hoped…don’t worry too much…unless you only drilled 3000’ of lateral.

Agree? Disagree? Send your thoughts to me at

The Future Evolution of Demand

The Future Evolution of Demand

Anyone who’s been in the oil business for more than, say, a month, knows how ridiculous it would be to confidently predict where oil and gas prices are headed.

Tensions in the Middle East, growing output from the Permian, offshore adds to reserves in Guyana and Brazil, uncertainty over tariff implementation, pipeline infrastructure buildout timing, tax policy implementation, legacy refinery crude quality limitations, storage builds, price of the dollar—these are just a few of the many drivers that affect wellhead pricing of oil and gas. It’s a thoroughly bewildering set of variables, and probably beyond the analytical capability of most mortals.

More often than not, our discussions and musings about oil and gas prices focus on supply.
So, I’m going to avoid putting on my dunce cap, but I am going to look at the demand side of oil and gas while questioning the assumptions we all make about hydrocarbon demand.

My guess is that most folks, when they think of future demand, envision the rest of the world achieving first-world status like Western economies did—through a drawn out industrialization process that required massive amounts of infrastructure and fuel to power the mobility of goods, services, and people.

We’ve certainly seen this in China and India, but are we considering the ways that technology can bypass the traditional routes to building wealth to “Western” standards?

Looking at cell phone adoption in Africa is instructive.

Over the course of just 12 years, South Africa has nearly tripled the number of its citizens who own a mobile phone, while Uganda increased its usage by a factor of seven!

Moreover, internet access is predominantly by smartphone, and although not yet dominant, smartphone ownership is projected to account for nearly 87% of all connections in sub-Saharan Africa by 2025.
The mobile overprint on the African economy is projected to add $45 billion to sub-Saharan GDP (

Here’s a technology that has leapfrogged the old model of landlines—without needing tens of thousands of miles of copper, hundreds of thousands of poles, and unknown hours, days, and years of trenching—and the power consumption to mine, smelt, transport, and embed the infrastructure.

Not to mention that it’s bypassed the last-mile problem of fiber.

Although cost of ownership is a stretch for many in the region, as is the case with many competitive commodity technologies, the cost of cell phones is dropping in the region.

Fine and good, we might think, but what about the fuel needs across the world to get people from point A to point B, especially in nations with huge populations.

Let’s look at the demographics.

China’s population will start to decrease within seven to nine years, but India’s will certainly pick up the slack. From now until 2058 there will be a net add of approximately 140 million people to the population represented by these two countries over nearly 40 years. That’s roughly 3.5 million people per year.
That’s a lot of added people on our planet, and this addition to world population by itself might make us believe that world demand for fuels would increase inexorably.

African population growth, however, will dwarf the net gain from India, adding more than 1 billion people in the next 25 years, or roughly 40 million people per year.

So, problem solved, right? A developing middle class in China (although dwindling and aging) adds more than 1 billion people in the next couple of decades, and they’ll all need cars to get around, capiche?

Perhaps, but will new third-world miles traveled mimic the American model?

To drive anywhere you need decent roads. Having hitchhiked in 1979 through what is now called the Democratic Republic of Congo, I vividly remember waiting for hours at a washed out portion of the road from Bunia to Bafwasende while trucks lined up on either side of a 15-foot pothole and took turns winching each other through the mud. The distance between the two towns is about 230 miles as the crow flies, or roughly the same distance between Lake Charles, Louisiana, and New Orleans.

The two Google Map images below compare roads in the Congo vs. roads in southern Louisiana.

If the roads are not there to be driven on, the picture that emerges for Africa is a growing population with lagging infrastructure development to support increased mobility. In other words, unfulfilled demand.

Should we be comfortable in assuming that the demand for mobility options is limited to internal combustion vehicles?

Admittedly, EVs (electric vehicles) don’t yet account for huge market share of transportation options, but the trend is growing. Although EV ownership in the U.S. lags ICE (internal combustion engine) ownership, the market share for EVs in the U.S. is forecasted to achieve nearly 22% in six years.

Given that Volvo, Daimler, Volkswagen, Ford, GM, and other vehicle manufacturers are increasing their fleets of both passenger and truck vehicles—including long haul trucks—it’s not unreasonable to speculate that EVs will make up a significant portion of the global vehicle fleet. Even China is directing its domestic auto industry to increase the percentage of EVs in their fleets.

Bloomberg forecasts increases in global EV usage to be about 23% of global vehicle ownership by 2040.

Maintenance cost for EVs are about one-third of those for ICEs, and power costs per mile for an EV are about 50% of fuel costs for ICEs, so the total operating costs for EVs are about 16% of the cost to operate an ICE vehicle. This is significant consideration that no doubt factors into the decision to go EV vs. ICE.

All well and good, but where does the power come from? In poorer countries the availability of power from centralized power generation facilities is often meager.

This is being slowly addressed by sovereign nation investments in power development, such as China’s $46 billion investment in Angola’s Caculo Cabaca Hydropower project, and its $2.5 billion investment in Guinea’s Kaleta hydroelectric facility.

Will less affluent countries need the range we require in the U.S.? Although there has been a pronounced migration of rural populations to dense urban cores in search of employment and wealth, I can envision scenarios where local development powered by better solar and wind power options could occur.

If so, the need for EV range could be significantly curtailed, and the lower the range, the more affordable the vehicle.

Moreover, there are low-cost options. India’s Mahindra e20 vehicle sells for approximately $8,200—affordable, especially if several individuals pool resources.

As far as I’m concerned however, the black swan in the whole picture is our ability to innovate.

The graph below gives a sense of how powerful innovation feeds on itself.

Improvements in battery storage technology, dropping costs of solar, the internet of things, materials research into substances such as graphene, and even 3D printing of houses will be just part of the technological revolution that will unfold, with, as of yet, unforeseeable impacts in how we live our lives—including how we obtain and use BTUs.

The demand side for hydrocarbon fuels is probably stable over the next 10 to 15 years, but after that, I think there’s real chance that world markets will see demand begin to soften.

Disagree? Have an opinion? Please let me know at

Geosteering—Are We There Yet? Part 2

Geosteering—Are We There Yet? Part 2

My last post on geosteering took a high-level look at wellbore placement across unconventional basins. In closing I promised to next look at some problematic areas—places where out-of-zone wellbore placement occurred at a higher rate than in well-controlled areas, like the Central Basin Platform, Mid-Continent, or the Midland Basin.

Let’s start by asking the question a few questions: Does being out of zone matter? Is production impaired by landing less lateral than planned in your target zone?

Since I called the DJ Basin problematic, and I received several comments from folks who are actively placing wells in the DJ, and who reinforced the idea that structural complexity causes the out-of-zone problems, I thought we’d start there.

Of the wells in our Play Assessments app that have targeted the Niobrara B as a landing zone, and for which we have directional surveys, nearly 28% have been characterized as having less than 75% of the wellbore in zone.

Compare the map below—colored by Peak Oil rates—of the wells in the Niobrara B that have 75% or more of the lateral in zone …

… with this map of the Niobrara B of wells with less than 75% of the lateral in zone.

Note that in the map of <75% in zone, there are fewer wells with higher peak oil rates.

Zooming in we can see that the distribution of “good wells”—using the assumption that high peak oil rates are a proxy for more favorable EUR values—is much higher in the “in-zone” map:

The following montage shows that wrench and other faulting with appreciable throw/heave occurs in the Wattenberg area and appears to persist to the northeast (for reference, red and pink boxes refer to the map and the well cross section in the montage below).

So, no mystery here. Faulting offset in the DJ through the Niobrara section requires out-of-zone wellbore path manipulation to stay on track to place the majority of the lateral in the upcoming downthrown fault block.

Interestingly, First 12 oil rates in the Niobrara B are counterintuitive. You’d think that the more wellbore in zone (100%), the higher median First 12 oil volume would be compared with wells with less wellbore in zone.

That’s not the case. The following graph hints that the opposite may be true.

Median proppant values are relatively consistent across all ranges of in-zone percentages, and as the graph below shows (for wells with less than 60% in zone) variations in proppant per perforated foot don’t correlate well with First 12 oil.

Perhaps, being more out-of-zone in the DJ implies greater faulting, and with greater faulting, chances are that natural fractures improve flow rates.

This kind of first cut evaluation will at some point need to be normalized for other important variables such as lateral length, frac job size, etc.

However, even when normalization is performed, there is still meaningful variability in results, as shown below (Niobrara—from DI Engineering Explorer).

We can conclude that using DI Play Assessments out-of-zone metrics can be used to high-grade basins, or areas within basins, that are likely to have higher percentages of wells with 75% or more of lateral in zone, but we should be careful about assuming that in-zone percentage correlates with better production values in faulted plays. In areas known to be faulted like the DJ, out-of-zone wells hint at faulting complexity and the enhancement to reservoir flow that natural fractures confers.

Naturally there are some outliers, so in the last part of the series I’ll look at some of these and then dig into production metrics.

If you’ve got perspectives on using in-zone, out-of zone percentages as drivers (or not) of production response please email me at