There has been plenty of public commentary about the loss of experienced older geoscientists and petroleum engineers simply due to aging.
The graph below, from an internal Exxon study, shows a trend from 2001–2013 their geoscience workforce sharply migrated toward older, retirement ages.
Dan Bilman’s 2014 article in the American Association of Petroleum Geologists (AAPG) Delegates Voice makes a similar point — many geoscientists in the oil & gas industry are at the latter stages of their careers. Based on his numbers, about half the population of the AAPG is 50 years of age or older.
While the Society of Petroleum Engineers (SPE) is bringing young engineers into their organization, their student membership growth is occurring outside the U.S. and Canada, and mainly in South America and the Asia Pacific region.
Growth in North America over the past five years is down for both members and students. The industry’s age demographics appear to be falling short of what the future will demand.
The “Great Crew Change” often evokes a fear that the insight into the practice of oil & gas geology, geophysics, and engineering — the retained knowledge of quirks in field geology and production engineering, ideas held in memory of undrilled “great” prospects, cautionary tales of “how it went wrong” in prospect definition methodology, or access to the wide knowledge network of older peers — will disappear when the older generation heads into permanent retirement.
When they go, the worry is that the hedge against risk these accumulated insights and skillsets the older generation represents, vanishes. Does it really matter, in today’s world of unrelenting focus on unconventional reservoir development?
The qualification of risk in oil & gas has changed from, “Will I make a well (i.e. do I have a large enough sealed trap with sufficient reservoir porosity and permeability)?” to “What kind of well will our engineers deliver to the bottom line?”
The prospect generators among us — the folks who worried about fault trend closures and the Wilcox, Frio/D sand/Muddy, and Rose Run isopachs, and looked for the Holy Grail of a large strat trap — are not in much demand these days. PE and institutional capital funds are backing unconventional reservoir plays because they are far better managed to margins, even if the per well payoffs are sometimes lower. Bankers are far more comfortable lending against engineering risk than against geology risk.
What I’m curious about is this — what, in this unconventional paradigm, is a newer generation of geoscientists confronting as project viability risk events?
Presumably, we all are aware of and account for industry risks as played out in price swing cycles. Some of us feel that there is NOTHING that replaces the terror of sitting in a logging trailer, looking at a down log to see if your target reservoir is at the structural position you picked, whether the resistivity values imply the presence of oil or gas (especially if your mud log has marginal shows), and whether the up-log porosity numbers help calculate out to good water saturation values.
You either make a well — good on ya, mate, beers all around — or you make that dreaded call back to the office or your investor group to tell them the acreage and dry hole money has yielded a loss.
What kind of bone shaking risk moments do the next crop of oil & gas professionals face in this unconventional world? How should their university education prepare them for these?
Maybe in this day and age of production-line factory drilling, the appreciation of risk gets lost in the accounting, the IRR calculations, and managing the margins.
Perhaps the worst case is being so far out of zone while geosteering that you lose your downhole motors and have to sidetrack, orthat your frac fluid does not make up properly and you won’t get enough of your expensive frac job pumped.
Either way, the asset value of a 50,000 acre Wolfcamp block is not significantly impaired by one or two unfortunate events — but if you find your target reservoir target 50 feet low to projections on a conventional well — that’s a complete project write off.
On a strategic level, there is risk in determining where and if the boundaries of an unconventional play can be expanded into an area of lightly drilled acreage that has been discounted due to minimal log control. These uncertainties can always be risked into a go-no-go acreage acquisition plan.
Whether geoscientists live in the unconventional world, the conventional world, or both, it is hard to let go of the idea that to earn your spurs in this business, you’ve learned some tough lessons about how risk really works, put your name behind a prospect, made a hard call, and risked nearly everything to get to TD.
Are exploration instincts being fostered and developed in the younger workforce in today’s companies? If so, how?
In the eyes of today’s managers, how important is it that their new geoscience and engineering hires have a seasoned understanding of risk? Do they value instinct as much as they value pivot tables?
I’d love to get your thoughts on what gut-stopping risk moments you’ve faced in today’s patch. Please forward any thoughts to me at email@example.com.
By now we’re all used to the latest analyst opinions on the prospects of share price gains for publicly traded companies in the oil and gas space.
Company X drills an extension well on a sweet spot trend and underperforms on well tests, and the stock sinks. Company A goes to the fringe areas of a play to escape high lease pricing, drills a well and –BOOM—they prove up a 50% increase in IP results and first 6 month decline rate forecasting, and they are Wall Street’s darling-du-jour.
What no one seems to be paying attention to, or giving companies credit for, is the uphole (or downhole) potential that can be unlocked in all those conventional reservoirs that are held by unconventional production
For example, if you pull all the production from a polygon that outlines Eagle Ford production in South Texas
DI Web app-AOI polygon search
you’ll find, once you export the production from the DI webapp and sort by reservoir name, that conventional reservoirs have produced about 2X Eagle Ford gas production and oil cumulative volumes that are comparable to the Eagle Ford.
Geologic and geophysical data densities have exploded in unconventional play areas. While the focus has rightly been on the geology of the unconventional target reservoirs—Eagle Ford, Niobrara, Haynesville, Bakken—tens of thousands of new wells, and untold square miles of new 3D seismic, open hole logs, and near bore microseismic, have greatly improved companies’ ability to identify and exploit uphole conventional completion targets.
This conventional lagniappe could ultimately provide the strongest economic foundation for an operator’s future operational cash flow, and given the longevity of production, can provide a great hedge against depletion timing risk—drilling and completing high-decline horizontals in times of less than ideal wellhead pricing.
To get a sense of how intermingled these opportunities can be, look at Pioneer Natural Resources operated production in Live Oak county.
Pioneer Natural Resources operated Production in Live Oak county
Focusing in the Lower Wilcox production established at Sinor Nest field (blue wells), the median cum BOE for these wells at around 8,000’ is just over 460,000.
Lower Wilcox production establised at Sinor Nest field
Median cum BOE for the Eagle Ford in their wells is just over 280,000.
Median cum BOE for Pioneer Natural Resource’s wells in the Eagle Ford
Now…the MONEY SHOT…median oil EUR for the Wilcox is nearly 850, 000BBL.
Median EUR for the Wilcox
Median Oil EUR for the Eagle Ford on the other hand is around 186,000 BO.
Median EUR for the Eagle Ford
With relatively flat decline in the Wilcox it’s easy to understand the favorable EUR stats for the conventional Wilcox…in this area.
DI Web App- Monthly Production
Conventional targets won’t be uniformly distributed over all unconventional acreage, but they will/can be an important element of the production prize secured by smart buyers in M&A acquisitions or public equity purchasers.
For example this map shows the presence of Olmos and Wilcox reservoirs, sized by first 60 month BOE over or adjacent to core Eagle Ford production.
DI Play assessments/DI web app—-green is gross Eagle Ford Graded acreage
Mapping Olmos thickness (over 50 separate reservoirs) shows that gross Olmos thickness in the Eagle Ford trend thins to the north and east, but that even in areas with less potential gross pay there is economic Olmos production.
DI Play assessments/DI web app—-Olmos thickness
And, there’s additional potential downhole as well—as this map of the Edwards first 60 month BOE production shows:
DI Play assessments/DI web app—-green is gross Eagle Ford Graded acreage
So the guidance is simple….recognize that unconventional drilling has added massive amounts of open hole logging and seismic data to the knowledge base of conventional reservoirs, and take note of the uphole and downhole potential of current unconventional producing reservoirs. Be prepared to ride that HBP potential in the future!
Exploit the fact that $/barrel, mcf break evens can be much lower for shallower conventional wells, and be prepared to profit from that conventional HBP potential well into the future!
Henry Hub at 3 and change, my prospect econ’s now in range!
Forgive the drivel but we, like you, are really excited about the near- and long-term future of the ‘patch’. The improvements in pricing have affected operations in EVERY basin, providing good to excellent margin support for deals and prospects far and wide.
Whether it’s someone trying play mid-Devonian carbonate reefal analogs out of the Alberta, Canada’s Golden Spike field (39,718,044 BBO, 37+ BCF–one well!!)
Drillinginfo Web app- Golden Spike field, Alberta,Canada—bubbled by cumulative oil
DI Web App-Mid Devonian Paleo-environment layer tied to Golden Spike field
DI Desktop-Well historical production, Golden Spike field
or someone else who’s gotten a farm-out in Eagleford country and wants to chase stray Wilcox of the kind that Pioneer found at Sinor West , Live Oak county
DI Webapp-Historical Production-#5 Sinor Ranch A, Live Oak Co, TX, L.Wilcox sand ,TD 8286’
there’s a lot of creative geology just waiting to be tested….probably with YOUR money.
So sign up for our Deal Desk at NAPE and check out the context of the hot deal that you’ve just seen—review type curves, water cuts, cum water, drilling activity, leasing opportunities…or walk through evaluation workflows on operators like Bonanza in the DJ Basin or Alta Mesa Holdings in the STACK.
If you wish to meet with our executive team to learn how to leverage DI’s enterprise value for your organization, sign up here.
We’re looking forward to meeting you at NAPE!!
Those of us who have focused our professional skills on domestic US oil and gas exploration and production sometimes lose sight of how actively international oil and gas concessions/properties/interest are trading hands.
Below is a quick collage of international assets transactions
Collage of international assets transactions
Since 1/1/2013 there have been 8677 asset transactions worldwide in which a working interest/participation did/would have changed hands. Since only 6% of these were cancelled, it’s fair to assume that the international oil and gas asset
market is active and reasonably healthy.
With about 6 more weeks left in this year, with no new deals 2017 will close out at the second highest level of ownership deal flow (transactions + pending deals) since 2013.
Graph of international asset transactions by year
We would expect the pace of international asset transactions to maintain this momentum as oil and gas pricing stays relatively stable (or increases) and especially if petroleum ministries (national and provincial) begin to incentivize investment of exploration and development CAPEX.
The largest transaction by acreage amount was Petronas’ 5/20/2014 purchase of STR Projetos e Participacoes Ltda’ 37.5% interest in lightly drilled Blocks 9 and 11… located NNW of Malakal and including Khartoum.., South Sudan [total acreage =68.8 million acres, or a piece of land measuring about 330 x 330 miles.
That’s a big chunk of territory.
Map of Petronas’ interest in Blocks 9 and 11
For perspective, this block of acreage would contain the entirety of the Permian Basin.
Map of the Permian for comparison
This transaction dwarfs any of the other 26 Petronas interest purchases ….they
must have seen a lot of East African Rift potential here, since only 6 wells have been drilled in the blocks, all of them are dry holes, and just one well had oil shows.
More recently, INEOS was very active in 2017, transacting for approximately 740,000 acres of mostly gas/gas & oil reserves.
Map of INEOS activity 1
Map of INEOS activity 2
INEOS’ gross 3,878,000 acre position (all years) is all European and is highly concentrated in the UK, and represents participation interests ranging from 10% to 50%. About 2/3 of the acquired interests are offshore,
Chart of INEOS acreage by country
There appears to be little correlation between acreage block size and % interest purchased, so it looks like INEOS is making very focused acquisitions.
Chart comparing Interest Purchased to Area ONSHORE
Chart comparing Interest Purchased to Area OFFSHORE
Our International subscribers can use all the information in Asset Allocations to
determine the patterns of buyers and sellers, and use the Block Card to assess
where buyers and sellers have other country assets that you should know about.
Example of a Block Card in the DI International Web App
Everyone follows US rig counts — it’s the most widely used 50,000’ proxy for gauging the health of the upstream oil and gas industry.
However, domestic observers need to realize that the industry has a vibrant international component that most analysts don’t pay attention to – most likely because most international exploration is still conventional in nature and project lead times and time to first oil is long.
Getting a sense of where international operators will be deploying their exploration and development capital is critical in assessing how to model, very roughly, potential additions to world reserves.
And knowing when they plan to do this allows us to leverage political perspectives into the mix.
Are wells planned to be drilled in politically stable or militarily fraught areas?
Are they timed to potentially avoid either national political crosscurrents or trending economic forces?
For example, the map below implies that exploration drilling on or close to Australia will not occur until the end of 2017 or later 2018, whereas there is a lot planned exploration activity in South America slated for the latter part of this year.
European exploration also looks to be concentrated towards Q#,Q4 2017, whereas West African planned wells are scheduled pretty evenly across the remainder of 2017 and into later 2018 (except for offshore Namibia)
Interestingly –in this search which was constrained from9/01/2017-12/31/2018—nearly 85% of the wells are classified as exploration, NOT development wells.
Intensifying exploration activity in Bolivia and offshore Brazil in Q3,4 and Q1,Q2 2018 would point to added interest in subsalt opportunities in Brazil and interest in the deeper section in Bolivia’s Andes foothills, going to 6100 est PTD in Pulspetrol Bolivia Corp SA’s Tajibo Sur X-2— nearly 3500m deeper than previous on trend wells.
Having a better understanding of the timing of potential new reserves additions is key to understanding how new reserves additions may match up—or not—with new global demand for oil and gas.