Verticals could be Key to Mississippi Lime Development

Most people probably associate the present and future of the oil and gas industry with horizontal wells and monster frack jobs in shale formations. That concept is driven by the idea that most of the shallow oil that’s easy to get to has been exploited, leaving deep plays in tight rock as oil’s last frontier. I’d respond to that argument with Lee Corso’s famous line, “not so fast my friend.”

The industry’s technological advances haven’t just improved horizontal drilling, they’ve improved vertical drilling as well. For instance, it’s now possible to drill a vertical well into a targeted zone and fracture the rock similar to a horizontal. This is an effective way to delineate acreage in formations that are characterized by multiple producing strata with “trapped” hydrocarbons like the Mississippian Lime, versus a resource play like the Bakken.

To illustrate this, SandRidge’s (SD) well results on the Western side of the Mississippian are all over the board. They’ve drilled wells like the Puffinbarger 2-28H which produced 51 thousand barrels of oil (MBO) in its peak month alongside a plethora of wells which never topped 1 MBO in a month. Out East it’s a similar story with Range (RRC) whose landmark Balder well produced 19 MBO in its peak month, but it has also drilled a number of wells which won’t top 19 MBO in their first year of production. The results are indicative of a play with high concentrations of oil in small areas “trapped” by faults, synclines, etc. versus widespread oil across a large area. 

These companies will tell you it’s a numbers game and the good wells more than make up for the bad ones. Even if this is true and companies are earning an acceptable IRR from their drilling program, is it really the best use of investor capital to be drilling a large number of expensive, uneconomic wells or is there a better way?

Austex (AOK) is a company that’s taking a different approach to the Lime. While the big companies are using data from the Lime’s old vertical wells to “delineate” acreage (the formation has a lot of historical production), it’s drilling new vertical wells with new technology to find oil. Once a high producing area is found, clusters of verticals can be drilled at 20 to 40 acre spacing. It’s early on, but the results of the program (see below) are looking solid.

Austex’ Vertical Well Results

Source: The Energy Harbinger / Oklahoma Corporation Commission.
1Production results during first six-months of well.
2Natural gas production isn’t publicly available. This number was calculated based on assumption of a 30% natural gas cut during the first 6-months of production.
3Cost per barrel calculated as estimated well cost divided by first six months of production.
4Estimated revenue generated from well during first 6-months of production. Assumed 85$ oil, $3 natural gas and 80% NRI.
5Cletus 20-5, Blubaugh 20-4 and Blubaugh 20-1 all share tank batteries with a second well making actual production from the individual wells difficult to determine. The production numbers shown are averages.

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The above table shows Austex’ vertical wells aren’t only consistent but they’re also nearly paying for themselves in six-months. These wells were all drilled in Township 25N, Range 1 East, Section 20, so it’s obviously a strong section for the company and may not be indicative of results across the play. Austex is a small company and doesn’t have the capital to drill a large number of wells at this point, but it will be interesting to measure consistency on the wells as the program develops. The company has 5,500 acres in this area, known as its Snake River Project, and plans to develop it at 40-acre spacing. 

When we contrast Austex’ results with those of Range’s horizontal program in the same area, we see they lack the consistency of the verticals.

Range’s Horizontal Well Results

Source: The Energy Harbinger / Oklahoma Corporation Commission.
1Production results during first six-months of production.
2Natural gas production isn’t publicly available. This number was calculated based on assumption of a 30% natural gas cut during the first 6-months of production.
3Cost per barrel calculated as estimated well cost divided by first six months of production.
4Estimated revenue generated from well during first 6-months of production. Assumed 85$ oil, $3 natural gas and 80% NRI.

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Range’s horizontal program boasts results which include the Balder 1-30N which is a best in class well (vertical or horizontal) and the Dark Horse 26-6N which might never recover its original cost. The company is probably drilling these wells to hold its Mississippian leasehold which consists of 160k net acres, so it’s not necessarily targeting its best acreage. With that said, why not drill more verticals whose cost per barrel of $61 per BOE (see footnotes above) is much less than the $243 per BOE it’s paying for horizontals? 

PetroRiver Oil (PTRC) is a micro-cap E&P whose acreage, located along the Nemaha Ridge in Southeast Kansas, is in the same geological area as Austex. The company’s team is made up of some of the key engineers and executives who designed Austex’ vertical program. Due to Austex’ success, it’s likely they’ll take a similar approach. Petro is definitely a company to keep an eye on in the Lime as they’re well positioned in a play with a lot of upside.

The Mississippian has gotten some bad press from companies like SandRidge and Range, as both have pumped the markets on the play’s economics and probably taken the wrong approach to development. While it’s not prudent to make decisions based on a few solid well results, I believe the geological characteristics of the Lime make vertical wells (at least initially), the best method to develop the play.

By. Braden Holt