Wildcatter Fever … Sort Of

Wildcatter Fever … Sort Of

Every once in a great while I have the luxury of scanning activity across the U.S. to find permitting or development I find interesting.

Below is a map of the 32,705 permits filed in the lower 48 in the last 12 months. The permits in green caught my attention.

NEVADA

I’ve always had a lot of respect for the explorers that somehow found a way to work through the complicated geology of the Basin and Range and discover oil in Nevada’s desolate Railroad Valley in 1954 from fractured welded tuffs at Eagle Springs field.

In 1976, Trap Spring was discovered and from fractured volcanic rocks. In 1983, Grant Canyon was discovered in Railroad Valley and produced from porous dolomite at rates around 6,000 barrels of oil per day.

Grant Canyon Oil & Gas LLC has taken a permit for an 11,500-foot well about four miles NNW of Blackburn field.

The eight producers at Blackburn Field have produced about 2.5 million BO, 2.5 BCF, and about 34 MMBW from depths of around 6,500 feet, so the added mile of permitted drilling true vertical depth (TVD) is thought provoking—to say the least.

Grant Canyon Oil & Gas LLC states in the permit that the well is being considered for unconventional well stimulation. But since the Nevada permit form does not indicate that the well will be deviated or horizontal, I wonder whether it’s a penetration and fracture stimulation of the underlying chainman high total organic carbon (TOC) source rock, or a lateral that will be landed in known Nevada reservoir.

NEW MEXICO

Gouger Oil Co. has filed a permit for a 7,800-foot vertical well in the very lightly drilled, non-productive Quay County, New Mexico. The well is a wildcat that aims to test the Granite Wash, which is pretty breathtaking, since the closest decent Granite Wash production in Oldham County, Texas—interestingly at around 6,500 feet—is nearly 65 miles ENE.

TEXAS

This is the most puzzling permit I found.

Maverick Energy filed a permit on Oct. 21 to drill vertically to 8,500 feet. The location of the well in Hudspeth County is 36 miles ENE of El Paso and nearly 70 miles west of the western edge of the Delaware Basin. And it’s in an area 10 miles west of the underwhelming production established by Trail Mountain Inc.

Why here? If they make a well, it would be one of the most interesting stories of the year.

VIRGINIA

A large number of CBM (coalbed methane) wells have been permitted by EnerVest (87) and CNX (99) in Buchanan and Dickenson counties in Virginia.

Median gas well cumulative production to date in the area for EnerVest (230,000 MCF) and CNX (315,000 MCF) indicates their CBM permitting program should bring in added, long-lived reserves.

Below is a map of CNX’s permitting (yellow diamonds) in Buchanan County and adjacent production.

Offset wells typically have the type of production behavior seen in the chart below.

It’s clear there’s virtually no dry hole risk, and with the expectedly shallow drilling depths, margins should be high.

Both CNX and EnerVest look comfortable in developing these reserves even with natural gas pricing at current levels.

NEW YORK

Since New York currently bans hydraulic fracturing, the state’s interesting permits will be for vertical wells. What interested me about the wells in southwestern New York was not so much the isolated and wildcat nature of them—as you can see, they’re very much within known play areas—but the economics of drilling them.

These wells in Cattaraugus County, New York, by Stateside Energy Group are permitted to a total depth (TD) of around 1,500–1,700 feet. They are surrounded by wells that have made meager production but look as if they might be on trend with slightly better producers.

Even with shallow total depths of around 1,500–1,700 feet, the drilling and completion costs should be, at a minimum, about $50,000. With offsetting Bradford wells making less than 100 barrels per well, it’s difficult to see any economic merit to this drilling program. It would make sense if the wells are being drilled to HBP the acreage for later development—maybe to twin Oriskany gas production found to the northwest?

It’s always enlightening to see how others are thinking outside the box.

Have a favorite wildcat or a unique play history you want to share?

Please contact me at mark.nibbelink@enverus.com.

Sharing the Gift

Sharing the Gift

For those of us who have had the great, good fortune to be paid to use our brains to find oil & gas, and to maximize its production, please give some thought to building that opportunity for the generations to come.

Building a career in the geosciences for a number of us was probably a given.

Dad or Mom worked in the oil patch and passed along compelling stories of the challenges of trying to understand how Mother Nature distributed oil & gas in reservoirs thousands of feet below us.

Our friends had parents who worked in the industry and we were constantly immersed in the culture of oil & gas.

For others, our path to exploration geology, geophysics, or petroleum engineering was probably, in large part, a function of luck.

For me, it certainly was.

I was a military brat. My dad was a career U.S. Army officer whose focus during the Cold War was the supply of and logistical support of the Army’s mission in Europe, then in Asia.

I remember him telling me about the time as a Lieutenant Colonel in Heidelberg, Germany, in 1957, he was charged by his commanding officer—a three-star Lieutenant General—with assessing the viability and merit of a two-star general’s proposal to fundamentally change the logistics models of the Army in Germany. It was important work, because it centered on how the Army and its allies would respond to a Russian invasion through the Fulda Gap in southern Germany.

My Dad sweated over this. He was reviewing the work of a West Point general and knew well the stakes for both the Army and his career if he messed it up.

He did his analysis, determined that the two star’s proposal was not viable, would cripple the Army’s ability to effectively support a war-fighting effort, and submitted his report. After a period of time, his commanding officer called him into his office, looked my dad in the eye, and said, “Nib, I agree with you.”

My Dad was relieved and elated. He had followed his own logic, assessed the evidence as honestly and dispassionately as he could, and was vindicated and supported.

My point is that as a kid, I was surrounded by families that had a narrow part of the Army’s mission in common. I never met a politician, or an investment banker, a lawyer—or a geoscientist.

I had no exposure to earth sciences, and certainly no familiarity or awareness of oil & gas exploration as a career.

Enter luck.

I went to college at Dartmouth, which is in New Hampshire, and it stays cold from mid-October through March. My freshmen year I thought I would be an engineer, but soon realized the way I thought didn’t align with the engineering mindset.

So, I was searching for a major. I had to take an elective and chose Geology 101.

Classes started in early January, so for the first three months everyone came to class in sweaters and parkas and long-sleeved shirts. In late March, the weather had warmed a bit, so one day my professor, Dr. Robert Decker, came to class, got ready to draw a diagram on the plastic sheet used with an overhead projector (no PowerPoint or computers back then), but stopped to roll up the sleeve on his left arm. And I was shocked to my core.

His arm was a mass of scars and burned tissue. He was a volcanologist and had gotten a bit too enthusiastic about sampling an active lava flow in Iceland. A bit of increased gas pressure in the flow blew out a chunk of lava that landed on his arm, burning him badly.

Yet here he was, in my class passionately talking about basic geology and enthusiastically pursuing his active research into volcanology. Nearly losing his arm didn’t deter him from his profound passion for geology.

Being the deep thinker that I am, I thought, “Hmm … there must be something to this geology thing.”

I declared Geology as my major and have been forever thankful that I did.

For young people in places like Terre Haute, Indiana, or Portland, Maine, or a hundred places you can name, there’s no oil & gas industry or presence to help stimulate their imagination.

Their parents are not going to be driving them by rigs with 30-foot substructures or pass a vibroseis crew thumping away. They’re not likely to overhear a rig hand talk about narrowly avoiding a blowout while taking a kick, a mudlogger enthusiastically describing a great crush cut, or a geologist pumped up about seeing pay at the expected depth on a down log.

They’re never going to be exposed to the magic of the greatest treasure hunt in the world.

So, let’s ALL do our part to reach out to children and school systems to share the magic of what we do.

On Oct. 13, Enverus was enormously blessed to be able to participate in the 20th Annual Austin Earth Science Week Career Day sponsored by the Bureau of Economic Geology.

We had the chance to meet young students—mostly middle schoolers—who were being introduced, for the first time, to the geosciences.

Anne Brennan, who heads up a team in Enverus’ Business Development group, was engaging and passionate in talking to young girls about her path into geology.

Enverus Technical Advisor, Sean Kimiagar, got students to hoist a small drill bit and showed them a great presentation about the lifecycle of oil & gas and talked enthusiastically to them about his career in the patch.

Even better, both Anne and Sean are keen to engage with young students more—with Anne looking to help out with The University of Texas at Austin’s Jackson School of Geosciences GeoFORCE summer field trip in Central Texas, and Sean by continuing to represent Enverus in coming years.

So when you have the opportunity to share the magic of your career in geosciences or engineering with a child, please go out of your way to do so. You might be firing up the next Michel Halbouty, Wallace Pratt, or George Mitchell!

If you have any education stories or insights that you want to share, please contact me at mark.nibbelink@enverus.com.

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 mnibbelink@enverus.com.

(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.)

U.S./World=6

U.S./World=6

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.

(Source: https://techcrunch.com/2019/07/29/tesla-has-a-new-energy-product-called-megapack/)

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:

(Source: https://www.bp.com/content/dam/bp/business-sites/en/global/corporate/pdfs/energy-economics/energy-outlook/bp-energy-outlook-2019.pdf)

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.

One.

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.

(Source: https://www.enverus.com/blog/conocophillips-buys-into-vaca-muerta/)

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.

(Source: https://www.mdpi.com/2073-445X/8/7/109/htm)

(Source: https://transafricapipeline.org/inside.php?page=about)

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 mnibbelink@drillinginfo.com.

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 mnibbelink@drillinginfo.com.