Hey, World – You’ve Got Some ‘Splaining to Do!

Hey, World – You’ve Got Some ‘Splaining to Do!

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?

Not enough.

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 mnibbelink@drillinginfo.com.

Hiding in Plain Sight?

Hiding in Plain Sight?

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:

  1. Old granitic basement to source He4 (the usable isotope)
  2. Recent compression heating and compression of the “source” rock to release the helium
  3. Transport of helium with natural gas, usually nitrogen
  4. Migration into a “trap”
  5. 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 mnibbelink@drillinginfo.com.

Conventional in Unconventional—Showin’ Some Love

Conventional in Unconventional—Showin’ Some Love

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
Conventional in Unconventional—Where’s The Love?

Conventional in Unconventional—Where’s The Love?

You’d think our industry, built on the broad shoulders of countless wildcats and new field discoveries, would have a soft spot in its heart for conventional prospects and targets. With Valentine’s Day just passed, however, we’re probably all reminded of past relationships that ended once we’d met our true love.

The industry’s “true love” these days are unconventional resource plays.

Wall Street’s analysis of the value proposition of unconventional oil & gas development is laser focused on the reserves potential of individual reservoirs — Eagle Ford, Haynesville, Bakken.

In the Permian, the investment community has talked at length about the stacked pay nature of the reservoirs — Wolfcamp and Bone Spring, for example — but there has been little to no discussion regarding potential uphole reserves in the fairways of the Eagle Ford, Bakken, Haynesville, and other resource plays.

Since these uphole reserves have, in most cases, not been targeted or tested with either dual completion (too much depth separation) operations or new wells, it’s understandable these “hidden” reserves are not part of the “normal” valuation discussion. There are just too few company press releases that give guidance on these potential assets.

Recently, I was looking at a well-respected company’s website and scouring through their press releases. All the commentary in quarterly earnings releases were focused mostly on Permian and somewhat on Eagle Ford operations. There was no mention — that I could find — of a shallower field development program that was 4,500 feet uphole to the primary target. This field is within the fairway of the primary target, and when net revenues from net production are added to the recent field asset sale price, this unexpected conventional prospect delivered an estimated 8-9X return on invested drilling and completion capital.

Consider how many wells have been drilled in unconventional plays that lie within known producing fairways of “normal” reservoirs. How much new data has been added to the geoscience database?

This map shows the general outline of Eagle Ford development.

There has been a huge amount of subsurface information added to the geology database in this area. If you add the 3D seismic that has been shot to fine tune wellbore positions and geosteering, it’s clear there is now a massive amount of new high-tech digital well and seismic information to support re-interpretation of CONVENTIONAL opportunities existing above and below the Eagle Ford.

This assumes, of course, Eagle Ford operators logged the open hole above kick-off points with good quality, well-chosen logging suites, or at the very least, had a mudlogger on location.

Assuming they did, what might they be looking at?

The map below shows wells with cumulative BOE values of 300,000 or more that were completed in non-Eagle ford reservoirs.

Note the variety of reservoirs flagged — San Miguel (AE-above Eagle Ford), Navarro sand (AE), Lower Wilcox (AE), Edwards (BE-below Eagle Ford). Other reservoirs in the mix include the Austin Chalks (AE), Olmos (AE), and Luling (AE).

However, the distribution of favorable reservoir facies in these clastic reservoirs can be complex. Reservoir development is patchy, non-linear, affected by faulting, and can change abruptly, as the following South Texas map shows.

(Source: DEPOSITIONAL SYSTEMS AND OIL AND GAS PLAYS IN THE CRETACEOUS OLMOS FORMATION, SOUTH TEXAS, Noel Tyler and William A. Ambrose, Bureau of Economic Geology, 1986)

(Source: DEPOSITIONAL SYSTEMS AND OIL AND GAS PLAYS IN THE CRETACEOUS OLMOS FORMATION, SOUTH TEXAS, Noel Tyler and William A. Ambrose, Bureau of Economic Geology, 1986)

All this new data should help to bring clarity to the geological interpretation of these complex plays.

It’s critical to realize a number of these fields were discovered many years before 1970, the first year the Railroad Commission of Texas (RRC) digitized production information. Anything before that is not available in digital form from the RRC.

For example, the Jourdanton (Edwards) field had first production in 1946. These early discoveries were made when 3D seismic was not the default standard for seismic data acquisition, so interpretations relied on fewer well data and the very gross statistical sampling of the subsurface inherent in 2D operations.

In 2006, Drillinginfo embarked on a very comprehensive project to digitize old field production records in Texas, Oklahoma, New Mexico, and Louisiana. In some cases, production volumes from the mid-to-late 1930s were captured.

The reserves potential in the reservoirs that have produced in these old fields may be unknown to many current unconventional operators simply because they don’t have access to this older production data. Companies that have seen steady retirements of experienced geoscientists may also find themselves lacking the broad play and reservoir insight retired geoscientists have developed.

Being unaware of true potential can be costly and leave money in the ground. For example, the Karon (Luling) field produced 5.5 million barrels of oil before 1970, which was 64% of its total field cumulative production.

Gas production for the field pre-1970 was 83.6 BCF, which represents 25% of total field production.

Without access to pre-1970 production data, a prospect generator might well conclude that with a median oil production of 10,552 barrels and median gas production of 1.19 BCF, an analogy to Karon field may not be worth chasing, especially in an era of weak gas pricing.

However, the median value for cumulative pre-1970 oil production is 56,474 barrels, and the pre-1970 median gas production value is 2.76 BCF.  There are five wells with first production pre-1970 that have produced more than 300,000 barrels of oil, whereas the post-1970 data has a maximum production volume of 169,900 barrels.

The Charlotte (Navarro) field, also produced 33 MMBO (64% of total field production) before 1970.

If the executive decision to ignore Luling, Navarro, or other conventional reservoir production is misinformed by its reliance on field or per-well cumulatives that do not include pre-1970 production, it’s likely the decision relied on grossly underreported EUR potential

That’s a big opportunity missed.

The story can be repeated in the DJ, Powder River, Haynesville, SCOOP/STACK, and other unconventional plays.

Equity analysts ought to be paying attention to this hidden uphole and downhole potential. Given the size of the possible reserves, and the shallow drilling (read inexpensive) drilling costs, these “hidden assets” could potentially have an NPV higher than their deeper unconventional brethren, especially if unconventional practices such as horizontal drilling are deployed in newly discovered, tight, “mature” conventional reservoirs.

How are conventional exploration opportunities being assessed at your company?

Are you showing them any love?

Let me know by emailing me at mnibbelink@drillinginfo.com. I’m a prospect generator at heart and am interested in your thoughts.

Is It Unconventional to Be Conventional?

Is It Unconventional to Be Conventional?

It’s blindingly obvious that our industry has focused on unconventional resource plays. We’re bombarded with news from most of the unconventional plays, treated to optimistic reserve forecasts from the biggest names in the industry, and stand back in something akin to awe when the USGS estimates 25 billion barrels of oil may be recoverable from the Permian. There’s very little coverage or attention paid to the conventional side of our business.

To get a bit of perspective, unconventional drilling measured depths (as measured by horizontal wells) total more than 2.7 billion feet. This is enough footage to circle the earth 21 times and is equal to more than 277,000 conventional wells with TDs of 10,000.

Rarely do we hear someone lament a dry hole, or the dreaded “geological success, economic failure” synopsis of a promising wildcat that TD’d high and wet.

Now it’s an entirely different dynamic..

Nearly 100% of every unconventional well that is completed produces oil, gas, or both. Drill an unconventional and you WILL make a well. If your company’s acreage position is large, there’s a reasonable chance that well No. 5 will be better than well No. 1, and you might be able to drill hundreds of “low risk” wells.

When defined as an assembly line process, nearly devoid of geologic risk, constrained by engineering best practices and not the whims of Mother Nature, it’s easy to understand why the unconventional revolution has had such an impact on U.S. E&P.

There are, however, some drawbacks to consider when evaluating the real value of an unconventional resource development plan.


The geographical integrity of an operator’s acreage position determines how much complexity is introduced to acreage development and well operations. It also defines how susceptible an acreage position is to uncontrolled offset fracture operations.

The map below, from the DI Web App’s LandTrac Unit feature, shows drilling units in a portion of the Eagle Ford play.

This map shows drilling units in a portion of the Delaware Basin (West Texas).

The difference is notable. In the Eagle Ford sample, there are large blocks of contiguous acreage, whereas in the Delaware Basin sample the checkerboarded nature of the drilling units means operators will frequently find themselves directly offset by competing operators.

Why does this matter?

Simply put, offset operations can materially affect the flow behavior and performance profile of a horizontal well

Offset hydraulic fracturing operations frequently require operators — if they even know that they are about to be frac’d into — to shut in their wells to preserve reservoir pressure as a defense against the migrating fluids of an offset frac job.

Pioneer Natural Resources addressed the impact of this by creating the Permian Operators Frac Schedule Consortia (https://www.spe.org/en/print-article/?art=3404). The consortium has 35 members (as of Feb. 1, 2019), and they share frac schedules with each other to help minimize the potential damage from frac hits.

It’s important to know when to be defensive, because most authors believe that shut-in periods are detrimental to well performance. Knowing when and how to do it to minimize damage to the flowback properties of the reservoir is key.

A number of authors (https://www.onepetro.org/conference-paper/SPE-165705-MShttps://www.onepetro.org/conference-paper/SPE-187506-MS) have concluded that prolonged shut-in periods can build an invasion zone next to the wellbore that materially affects flowback performance of oil & gas, as the graphic below implies.

The effects of even moderate shut-in periods can be detrimental to a well’s performance. Being offset by several adjoining operators whose drilling operations can materially affect your reserves bookings is not a good thing.


The complexities of unconventional field development only increase when the holy grail of optimum down spacing is pursued. The technical planning needs — cross-disciplinary collaboration among geology, geophysical, petrophysical, engineering, and land teams — and execution of field development in a “significant,” large-acreage position unconventional play are daunting.

It might even be fair to say they require many more personnel than the number required to execute a drilling program on a portfolio of good conventional prospects.

Combining the added level of planning and execution complexity inherent in an unconventional drilling program, with the added unknowns of defending against offset operators can, and probably does, lead to longer decision-making processes. This introduces delays in bringing production to the tank battery and so affects CAPEX NPV.


Of course, the biggest risk is wellhead pricing. Price uncertainty — from the highs of 2014 to where we are now — has been a brutal lesson in volatility.

A quick look at the Eagleville field in south Texas is instructive.

If we use DI Desktop/Wellcast to pull all wells in Eagleville field with first production dates from Jan. 1, 2014 to present (6,572 wells), we find 1.389 billion barrels of oil were produced. Approximately two-thirds of this volume was produced and represents about 35% of the total recoverable reserves of the field during periods of low pricing — as shown by the graph below.


Benchmarks that operators value as best practices are continually changing.

More proppant, less fluid? More proppant, more fluid, fewer stages? More stages, different frac job chemistries?

If each well’s completion is considered an experiment, a drilling development program should be considered a series of experiments. Good results can be confidently expected to improve IP or peak oil rates, but what certainty do they confer on the cash flow metrics that matter — 24- to 36-month cumulative production and ultimate recoveries?

Not every operator climbs the learning curve with equal speed.

The creaming curve chart below shows the rate at which some operators in the Delaware basin are accelerating their ability to add production. A more inclined graph means the operator is adding production — per well — at a faster rate.

The close-up below clearly shows that the operator represented by the gold curve is adding reserves/wells at a more efficient rate (red arrow) than the operator represented by the light blue curve. However, the operator associated with the light blue curve made a major change in operations after well 121 and started adding production at a more efficient rate (graph above).

Endemic to unconventional plays is what I call persistence risk — continuing on a planned path of action with less than perfect visibility into the outcomes. When does an operator know its completion methodologies are optimal? When can it finally have good visibility on its EUR and RRR metrics?


Conventional drilling programs, on the other hand, have some major advantages.

Assuming a company’s geoscience team is very good, some of the risks that are integral to unconventional development are moderated or disappear completely.

There is no persistence risk. Drill a dry hole that clearly condemns a prospect, you’re out limited acreage costs and dry hole money, but you have better clarity on where to spend your next upstream dollar.

By and large, the drilling and evaluation process is much simpler, requires smaller teams, and as a result, minimizes the potential for organizational inertia or miscommunication.

Although never perfect, reserves estimation can be more straightforward because the trap volume — the reservoir container — is more easily measured. This means a much clearer measurement of ROI on spent capital, and a clearer picture of the capital structure necessary to execute on strategy.

Although a conventional prospect will be as economically impaired as an unconventional prospect during times of low product prices, it will have a longer producing life with gentler decline that can provide a hedge against bad price environments. In other words, there’s production in the good times to help restore revenue lost in the bad times.

The graphs below plot production over time against the oil price for a Rockies well with excellent reservoir porosity/permeability vs. a Bakken unconventional well. Note that half of the cumulative oil produced in the Bakken well was produced during a period of low prices. In contrast, half of the cumulative oil produced in the Rockies well was produced during both low and high priced environments.

Vertical conventionals targeting traditional, good porosity reservoirs cost less since they don’t incur the massive horizontal and fracturing expense their unconventional shale brethren require.

Let’s do a quick bit of napkin economics. Suppose company A has an annual $100 million drilling budget. If they focus on an unconventional reservoir project comprising 8,000 acres with lease costs of $5,000 per acre, they plan for 80 acres of spacing, and their D&C well cost is $6 million per well, they could expect to drill 10 wells to HBP critical lease positions in their block and thus drill out their current year CAPEX budget.

Say, instead, company A chooses to explore for conventional traps.

Perhaps they’ve determined to generally stay above geopressure and limit their TD to depths of 10,000 feet or less.

At a maximum drilling and completion cost of $2 million per well, and prospects of around 2,500 acres in size (think Pioneer’s Sinor West field in Live Oak County), company A could test 20 separate prospects for reserves that could range from 15 MMBO (Sinor Nest, Wilcox ss 13 wells),TX to 42MMBO at Covenant field, (Navajo ss, 38 wells) UT.

Just one success in 20 could deliver reserves equivalent to the proved reserves attributable to the unconventional option. However, is it reasonable to think that a 5% success rate is achievable? Given all the 2D and 3D that has been shot, the massive amount of new information that has been added to our geological database, and the sheer competency of geoscience teams armed with good software, I think it’s reasonable.

For my money, I’d be allocating a higher proportion of my E&P CAPEX to traditional, conventional prospecting.


There are plenty of places to look.

For example, our Alberta, Canada, data, when scatter plotted in DI Desktop, shows a lot of potential per well recoveries above 2 million BO per well, with activity in the last 10 or so years implying even greater potential.

The Turner play in Wyoming’s Powder River Basin has exploded since early 2012 by applying unconventional horizontal drilling and applying it to a “regular” but tight oil sand reservoir. What other conventional reservoirs might be both conventional reservoirs with an unconventional twist?

Geographical reconnaissance is easy to do. Assuming you know the reservoirs you want to play, you can scatter plot them in DI Desktop and find their distributions of cumulative oil, etc., by county.

The Rose Run scatter plot below shows that about 10 counties have accounted for most of the Rose Run’s production.

Instead of grading by reservoir, data can be high graded by cumulative production. For example, wells having produced between 500,000 and 1 million AND constrained by TD equals less than 10,000 feet.

The map below shows a sample from Louisiana, Arkansas, Mississippi, and Alabama.

The DI Desktop scatter plot below now shows a partial sample of oil cumulative production plotted by county. This can be used to start investigating the counties that show an attractive distribution of high volume, vertical wells with TDs less than 10,000 feet.

Is your company, partnership, or PE group thinking about building more conventional opportunity into your CAPEX budget?

If so, I’d love to learn the logic that caused you to re-balance your energy CAPEX portfolio.

Send your thoughts to me via email at mnibbelink@drillinginfo.com.