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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. 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 ( 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 [email protected].

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Mark Nibbelink

Mark Nibbelink is co-founder and director of university outreach at Enverus. Before co-founding Enverus (formerly Drillinginfo) in 1999, Mark had a long career as a prospect geologist at Gulf Oil before beginning work as an independent geologist. Mark is responsible for quality control and data integrity. He received his Bachelor of Arts in geology and his master’s in geology and geophysics from Dartmouth College.