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 deep 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.

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 25 North, 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.

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.


Largest Oil and Gas Wells by Formation

Note: Added Powder River Basin well on June 10, 2013

I don’t usually talk about “largest wells” in formations or plays because they aren’t representative of the productivity or economics of a play as a whole. With that said, it’s still good to know where the biggest wells are being drilled because that usually indicates there’s a lot of oil in the area (whether it can be extracted consistently and economically is another matter).

Note: Peak month rate oil/gas is the amount produced in a given month divided by 30 days.

Well Name: Behr 11-34
Operator: Whiting (WLL)
County, State: Mountrail, ND
Formation: Bakken
Spud Date: April 15, 2008
Peak Month Rate Oil: 1,492 BOPD
Peak Month Rate Gas: 1,008 Mcfpd
Cumulative Oil: 911,627 BO
Cumulative Gas: 558,996 Mcf
Latest Monthly Rate Oil: 273 BOPD
Latest Monthly Rate Gas: 242 Mcfpd
Source: North Dakota Oil & Gas Commission/The Energy Harbinger.

Well Name: Jendrusch Unit 1H
Operator: Plains Exploration and Production (PXP)
County, State: Karnes, TX
Formation: Eagle Ford
Spud Date: April 21, 2012
Peak Month Rate Oil: 2,551 BOPD
Peak Month Rate Gas: 3,917 Mcfpd
Cumulative Oil: 341,352 BO
Cumulative Gas: 629,981 Mcf
Latest Monthly Rate Oil: 681 BOPD
Latest Monthly Rate Gas: 1,825 Mcfpd
Source: Texas Railroad Commission/The Energy Harbinger.

Well Name: Frye Ranch 2012H
Operator: Forest Oil (FST)
County, State: Wheeler, TX
Formation: Granite Wash/Hogshooter
Spud Date: March 23, 2010
Peak Month Rate Oil: 2,149 BOPD
Peak Month Rate Gas: 20,630 Mcfpd
Cumulative Oil: 327,782 BO
Cumulative Gas: 6,081,260 Mcf
Latest Monthly Rate Oil: 70 BOPD
Latest Monthly Rate Gas: 1,444 Mcfpd
Source: Texas Railroad Commission/The Energy Harbinger.

Well Name: Livestock 1-25H
Operator: SandRidge Energy (SD)
County, State: Grant, OK
Formation: Mississippian Lime
Spud Date: March 18, 2012
Peak Month Rate Oil: 1,595 BOPD
Peak Month Rate Gas: 3,909 Mcfpd*
Cumulative Oil: 170,398 BO
Cumulative Gas: NA
Latest Monthly Rate Oil: 214 BOPD
Latest Monthly Rate Gas: NA
Source: Oklahoma County Commission/The Energy Harbinger.
*Natural gas data is not publicly available for this well. Rate was computed using IP rates in the completion report.

Well Name: Dolph 27-1HZX
Operator: Anadarko Petroleum (APC)
County, State: Weld, CO
Formation: Niobrara
Spud Date: January 9, 2011
Peak Month Rate Oil: 730 BOPD
Peak Month Rate Gas: 1,595 Mcfpd
Cumulative Oil: 154,287 BO
Cumulative Gas: 568,554 Mcf
Latest Monthly Rate Oil: 71 BOPD
Latest Monthly Rate Gas: 331 Mcfpd
Source: Colorado Oil and Gas Commission/The Energy Harbinger.

Well Name: Anderson 18H-1
Operator: Encana (ECA)
County, State: Amite, MS
Formation: Tuscaloosa Marine Shale
Spud Date: January 15, 2012
Peak Month Rate Oil: 840 BOPD
Peak Month Rate Gas: 267 Mcfpd
Cumulative Oil: 115,991 BO
Cumulative Gas: 35,075 Mcf
Latest Monthly Rate Oil: 169 BOPD
Latest Monthly Rate Gas: 54 Mcfpd
Source: Mississippi Oil & Gas Board/The Energy Harbinger.

Well Name: Federal 16-10/3FH
Operator: Helis (Private)
County, State: Converse, WY
Formation: Frontier
Spud Date: July 16, 2011
Peak Month Rate Oil: 1,198 BOPD
Peak Month Rate Gas: 1,461 Mcfpd
Cumulative Oil: 270,530 BO
Cumulative Gas: 272,705 Mcf
Latest Monthly Rate Oil: 281 BOPD
Latest Monthly Rate Gas: 258 Mcfpd
Source: Wyoming Oil and Gas Conservation Commission/The Energy Harbinger.

For those of you who use the prototype version of the The Well Map, this is the type of data you’ll be able to access using the full version which will launch this summer.

Disclaimer: These are the largest wells in the above formation that I’m aware of. If you know of larger ones, feel free to disclose.

Macro U.S. Oil Data (2002/2012) + Energy Independence Musings

I felt it was time to get some macro data on this site which provides perspective for some of the “hot-button” words heard in the news media like “energy independence.” The data below compares oil and petroleum product imports during 2002 and a decade later during 2012. The U.S. imported 3.9 billion barrels of oil* (BBO) (10.6 MMBOPD) during 2012 or 8% less than the 4.2 BBO (11.5 MMBOPD) it imported in 2002.

We also used less oil in 2012 as consumption dropped 6% to 6.8 BBO (18.5 MMBOPD) compared to 7.2 BBO (19.8 MMBOPD) in 2002. Imports as a percent of total consumption have dropped from 58% in 2002 to 57% in 2012, meaning we’re not importing significantly less petroleum contrary to what many would hope as domestic production increases.
*When I refer to oil in the above paragraph, the figure includes petroleum products (see below for definition).

Let’s answer the next natural question here, how much did domestic oil production really increased during the decade in consideration? In this section we’re going to look at just crude oil which would be distinct from petroleum products.

U.S. Crude Oil Production (2002 to 2012)
Source: EIA.

Domestic crude oil production increased 14% to 2.4 BBO (6.5 MMBOPD) in 2012 from 2.1 BBO (5.7 MMBOPD) in 2002. This of course doesn’t tell the full story as crude production was tanking circa 2008 before shale production ramped up and changed the course of our energy history. I’d have to imagine there would be a lot more support for the Keystone XL pipeline if U.S. oil shale hadn’t been exploited.

If you’re wondering about exports, we shipped approximately 22 MMBO (60 MBOPD) across borders during 2012, 564% more than 3.3 MMBO (9 MBOPD) in 2002 and 49% less than 43 MMBO (118 MBOPD) in 1999. While exports increased quite a bit over the time studied, 22 MMBO is a spit in the proverbial bucket.

All in all, it doesn’t seem like we’re a whole lot closer to energy independence than we we’re during 2002 as even domestic production hasn’t increased that drastically when you look at the period as a whole. With that said, when most people think about energy independence, they’re probably throwing Canada into the mix which makes the concept slightly more feasible while also putting our energy fate in the hands of heavy crude, a dirty proposition.

U.S. Imports of Oil and Petroleum Products by Country (2002 and 2012)
US-Oil -Import Data_2002-2012
Source: EIA
*Click here for definition of petroleum products.

The graph above shows we’re importing a lot more oil from Canada and significantly less from states like Saudi Arabia, Mexico and Venezuela. The decreases in Saudi Arabia/Venezuela are probably political decisions to wean ourselves off of Middle East oil/regimes we don’t want to support financially. Mexican oil production has decreased due to depletion of fields and or lack of exploration by its oil companies. The one surprise on here might be the increase in purchases from Russia and Columbia, two countries who’ve picked up some of the slack from our declines elsewhere.

EOG’s Horizontal Wells in the Greater Green River Basin

I’ve had a bit of a posting hiatus but I plan to continue to keep this blog updated, I’ve just been busy. This post will focus on production results from 27 horizontal wells drilled by EOG Resources (EOG) in the Greater Green River Basin (see map below) in Southwestern Wyoming. These wells were drilled between 2006 and 2010 and produce from the Frontier interval which is a natural gas zone. For reference, the Frontier interval is a similar but older age rock than the Lance interval which is the productive zone at the Pinedale and Jonah fields in the Greater Green River Basin.

Map of the Greater Green River Basin
Source: USGS.

The average 30-day production rate from these wells is 1,430 thousand cubic feet of natural gas per day (Mcfpd) which corresponds to an average recovery of 369 million cubic feet of natural gas (MMcf) after one-year of production and 813 MMcf after three-years of production. Regarding the 27-wells, range of recoveries is wide with a maximum three-year recovery of 2.0 billion cubic feet of natural gas (Bcf) and a minimum of 145 MMcf.

So how economic were these wells? I haven’t been able to find any information regarding cost, but what I can do is take a look at natural gas prices from 2006 forward to ballpark what these wells have grossed to date.

Annual Natural Gas Wellhead Prices (2006-2012)
Natural gas-wellhead-prices
Source: EIA.

If we use $5.45 per Mcf (average price from 2006 to 2011) as the average price received per Mcf of natural gas and 813 MMcf as the average three-year recovery, we can see that these wells grossed an average of $4.4 million during their first three years of production. Without knowing well cost, we’re kind of left hanging here, but I do have a log (shown below) from an EOG well drilled in the Green River Bend field which shows depths in the 7,000′ to 8,000′ range.  Based on this, I’d assume they were each drilled and completed for approximately $5 to $6 million.

Green River Bend Well Log
Source: USGS.

So what’s the payback period looking like? Assuming an 85% NRI and $5.5 million well cost, I’d guess these wells would need to produce approximately 1.2 Bcf per well with approximately 3 thousand barrels of oil to break-even. These wells only declined 30% from year one to year three, so they project to have a long production life. Knowing the above, I’d guess the payback period for 2006 to 2009 generation GRB Frontier wells is five to six years or triple the length of the average Bakken well drilled today.

With that said, the purpose of this write-up is to provide data on a pure natural gas play, something I haven’t done much of on this blog to date. Even though oil is currently more economic than natural gas, natural gas is going to play a larger role in fueling the world moving forward so it makes sense to familiarize ourselves with the potential of some of these formations.

Last, I thought I’d toss in a couple scatter plots on the wells used in this analysis. As shown below, it’s pretty easy to tell how economic a natural gas well in this field will be based on the 30-day production rate.

Green River Basin Production (Frontier Zone) Year 1

Source: Wyoming Oil and Gas Conservation Commission/The Energy Harbinger.

Green River Basin Production (Frontier Zone) Year 3
Source: Wyoming Oil and Gas Conservation Commission/The Energy Harbinger.

The Bakken’s Stacked Pay Zones

Continental Resources (CLR) came out with data last winter indicating that at least some of its acreage in the Bakken would be prospective for stacked pay zones. The evidence it provided was results from its Charlotte Unit wells in McKenzie County where the company was producing from three zones, the Middle Bakken, Three Forks 2 and Three Forks 3 (see stratigraphic column below).

Source: Continental Resources Corporate Presentation

As you can see from the picture above, the company’s success in the Three Forks increased its oil in place estimates for the Bakken Petroleum System to 903 billion barrels of oil (BBO) from 507 BBO and recoverable reserves to 32 BBO at a 3.5% recovery factor. CLR has a lot of work to do to prove this assertion and it will be delineating its acreage for multiple Three Forks zone potential.

Producing from the Three Forks is nothing new in the Bakken, but what’s interesting is that CLR is producing from multiple Three Forks (TF) benches which may prove the potential of multiple reservoirs in the Bakken thus more reserves than what has been produced in the Middle Bakken.

I don’t have CLR’s well data organized well enough to show you the results of its TF wells.  Part of the problem is having to dig through well files which are large documents that take a long time to open on North Dakota’s Oil and Gas Division website.  Luckily, some companies give us clues that a well is a Three Forks well by putting “TFH” or Three Forks Horizontal in the well title.

Marathon Oil (MRO) is one of these companies and I have data from 26 of its wells across Mountrail and Dunn Counties, half of which targeted the Bakken and the other half Three Forks. These wells were drilled very close to each other in pairs indicating that the company believes each section is economic for both the Bakken and Three Forks.

Note: When I say the wells were drilled very close, I’m saying same quarter section at minimum with parallel lateral legs.

Cumulative production from Stacked Pay Zones
Marathon Oil_Bakken-Three-Forks-Cumulative-Production
Source: North Dakota Oil and Gas Division / The Energy Harbinger.

I’ve color coded all of the above Bakken wells in green and TF wells in red.  The first two wells, Rhoda 24-31H and Oren USA 31-6 TFH, are a pair of wells which were both drilled very close to each other but in different zones.  What needs to be determined to prove that the Bakken and the Three Forks are separate reservoirs is that the cumulative production will not be effected by the drilling of either well, that is that one well is not draining oil from the other thus resulting in you drilling two wells for the price one.

All of these wells were drilled during 2011 and 2012 and the quick and dirty average cumulative production from them is 97 thousand barrels of oil (MBO) and I usually use 150 MBO as a target for payback from a Bakken well.  This would indicate that these wells are paying back in two to four years which is a solid result and compares well with the company’s historical production in the Bakken.

There’s a lot more to talk about and analyze with regards to this topic and the implications could be large.  For instance, if I have 100 Bakken well locations in my inventory but find out the Three Forks zone is productive in all of those same areas, I now have 200 well locations.  All of the above wells were drilled in clusters across both Dunn and Mountrail County, meaning Marathon either doesn’t think most of its acreage is prospective for multiple zones, it’s capital has been tied up in the Eagle Ford where returns are better or it’s not following the same naming system with all of its TF wells.

I will be looking into the above for MRO as well as where other companies are drilling TFH wells in the Bakken.  When I have more data on CLR, MRO, etc I’ll be writing another article.

The Well Map Update (3-20-13): Feedback

When I initially started working on The Well Map, I was planning on building a dynamic filter into the free version you see today, before moving it to a new web platform where access would be restricted to paying customers.  Don’t plan on the former being available, however there will be a free demo map with limited well map data points once the new site launches.

The new site is currently under development with an expected launch date of June, 2013.  The map will have multiple filter options for county, operator and well name in addition to ranges for spud date, oil/gas production rates (30-day and cumulative), and oil cut.  There will be other features built into the map too which are designed to make your experience a good one.

Are there any functions I’m  missing that any of you think would be useful?

I’m also working on building in analytics to support the map data, one piece of which will be average NGL cuts where applicable as public data doesn’t break these out at this point.  Are there any other analytical pieces that you think would be helpful?

I appreciate your feedback as me and my team work to complete the first build of this website.

Excerpts from Earnings Transcripts (DVN, NBL, SD, CRZO, MRO, AREX)

I regularly spend time digging through earnings transcripts as I research the various companies and formations I write about.  While it’s currently post earnings season, I thought I’d post a few notes from earnings calls from several companies I’ve recently looked at.  These notes aren’t necessarily the most important points from the call, just ones that interested me.

Devon Energy (DVN)
* D&C six wells in the Cline Shale with “highly variable results.”  Plans to drill 30 more exploration wells in the formation testing various intervals.
* Regarding variability of the Cline results, the company mentioned it’s testing different areas of acreage position and different intervals to see which work best.  It’s confident the play will be economic.

Source: Q4 Earnings transcript (Click here for transcript).

Noble Energy (NBL)
*Plans to test 350k net acreage position in NE Nevada with vertical wells.
*Plans to test 1.8 MM net acreage position in offshore Nicaragua.  (Noble, Niobrara, Nevada, Nicaragua…what’s with that?)
*Will spud exploration well at Karish (follow up from Leviathan 4) in the Eastern Mediterranean.
*Plans to drill 5 to 10 wells in Northern Colorado (North of Wattenberg) where company has 230k net acres (versus 290k net in Wattenberg).
*2013 Drill plan for DJ Basin is to spud 300 wells.

Source: Q4 Earnings transcript (Click here for transcript).

SandRidge Energy (SD)
*90% of rate-of-return (ROR) of a Mississippian Lime well is recovered in its first five years.
*Lowered EUR estimate in Miss Lime to 369 MBOE from 433 MBOE.
*Company projects to move well cost in Miss Lime below $3 million (not including SWD) by end of 2013.
*In 2012, the company produced 10.1 MMBOE (45% oil), a 163% increase compared to 2011.
*2013 plans include D&C 581 horizontal wells and 74 SWD wells in the Lime.
*Agreement with Atlas Pipeline Partners allows for capture of NGLs from Lime.

Source: Q4 Earnings transcript (Click here for transcript).

Carrizo Oil & Gas (CRZO)
*In the Niobrara the company is producing 800 net BOPD on 33 gross wells with five more gross (2.4 net) awaiting completion.
*Plans to test Niobrara down to 80-acre spacing .
*Niobrara wells are 80% oil.
*In Guernsey, Ohio (Utica Shale), CRZO expects 50% to 75% oil cuts with the remainder wet gas (Antero, PDC and Gulfport wells cited).
*50% of the company’s NGL production in the Eagle Ford is ethane; company also makes point that 90% of revenues from Eagle Ford are from oil.

Source: Q4 Earnings transcript (Click here for transcript).

Marathon Oil (MRO)
*70% of Eagle Ford wells will be drilled on pads in 2013.
*D&C costs in the Eagle Ford are now averaging $8.5 million but company expects this to drop to $8.1 million over the near term.
*Bakken wells are being completed at $8.5 to $8.8 million.

Source: Q4 Earnings transcript (Click here for transcript).

Approach Resources (AREX)
*Estimated 2,000 gross drilling locations in the horizontal Wolfcamp play (includes A, B and C benches).
*Average well should be in the 450 MBOE range with D&C costs $5.5 to $6.0 million.
*Expects to recover 85 to 90 MBOE in first year of average well.

Source: Q4 Earnings transcript (Click here for transcript).