Scoop & Stack

Trackin’ Back to the STACK

We began our STACK coverage in March of last year by focusing on the work of pilot well programs.  Its been nearly a year since we checked in on the development of the Play, so I thought we would start 2018 off with a look back on the STACK and update you on the most recent activity.  But, first a brief review of the key takeaways from 2017’s 4-part “Trakin’ the STACK” series.

What is a “pilot well” program and why are they important?

Pilot wells are key to the development of new areas as they provide opportunities for companies to learn about their targeted formation(s) and how best to develop them.  In the early stages of development, before full-fledged drilling and production, companies conduct pilot well projects to determine formation characteristics such as rock properties, bottom-hole pressures, and fractures.  On the completion side, companies will experiment with completion formulas, ideal well spacings, and methods of managing well interference during fracing.  Pilots will also help determine potential risks to drilling, operations while maximizing lateral lengths.

The most common types of pilot programs in the STACK since the earliest days (circa 2015-16) have been density, risk assessment, and completion recipes with density pilots being most widespread.  Commodity prices may affect well spacing, especially when favorable pricing may induce operators to accept higher well interference levels to boost production.

The graphics below depict a few of the most notable pilot wells in 2017 as well as operators whose early pilot wells had significant initial production rates above 1,000 BOE.

Overall, here’s how the operators stack up regarding the number of pilot well projects and wells they’ve undertaken.

Later in this article, we’ll look back at these wells and check in on other development by leading operators in the Play.

2017-18 STACK trends

As I’ve watched activity in the STACK for nearly a year, here are some of the trends that have recently emerged.   You’ll see most of these themes throughout the remainder of this article. 

  1. Bigger fracs – today, it’s not unusual for operators to use thousands of pounds of sand and water per lateral foot. Cimarex, for example, used about 1800 pounds of sand for its Meramec wells in the Summer of 2015.  By last summer, the company had increased its sand usage by 1,000 lbs to 2800 pounds per lateral foot.
  2. Longer laterals – Many operators are drilling laterals upwards of 10,000 feet more often than 1-mile laterals. Alta Mesa still prefers the results from their shorter 4,000’ – 6,000’ laterals as they drill in the shallower Oswego/Meramec formations.
  3. Tighter well spacings – Devon’s Showboat project has one of the densest planned developments at 13 wells – 12 wells targeting the Upper and Lower Meramec and one well targeting the deeper Woodford. Continental and Newfield also have 10-12 well density projects.
  4. Multi-well pad drilling – Most operators are creating efficiencies and capitalizing on the economies of scale that multi-well pads offer.
  5. Westward expansion – Continental and Alta Mesa are examples of 2 operators expanding into the over-pressured region west of their original STACK positions. Continental is moving into Dewey County while Alta Mesa is expanding northwest into Major County from its base in eastern Kingfisher county.
  6. Development drilling – With much of their appraisal work completed, some operators have moved closer to full field development while others are still in the evaluation phase.
  7. New technologies are positively impacting operator’s bottom lines. Newfield’s Velta June pilot is an example to watch.

How are the leading Operators STACKing up?

Alta Mesa has conducted some of the oldest spacing tests in the original STACK core and is shifting from delineation to development. The company’s drilling targets are shallower STACK formations such as the Meramec, Osage, and Oswego formations.  They rely on drilling shorter laterals, around 5,000’ with increasing densities citing drilling efficiencies and lower development and completion costs as a rationale.  Alta Mesa’s primary footprint is in eastern Kingfisher County where they have amassed large blocks of contiguous leasehold concentrated across 11 townships.   The Company is also developing their acreage in the up-dip oil window which extends northwestward into Major county where Alta Mesa has nearly six townships of contiguous leasehold.

Cimarex is an early horizontal driller in the STACK and owns a substantial inventory of high-producing wells in the Play despite their less than ideal lease position.  The company is still delineating their operational areas while testing completion strategies.  Cimarex is also participating in 20 STACK pilots while their pilot, the Leon Gundy, (a Meramec/Woodford stacked, staggered project) has been producing for over a year with production surpassing the 2,000 MMcfe mark.

In my first article on STACK pilot projects in early 2017, Continental Resources had seven density pilot projects, the most of any operator at the time in the over-pressured portion of the Play.  During the latter half of this year, Continental has reported several noteworthy wells with initial production rates ranging between 1,000 – 6700 BOE per well.   Furthermore, according to the Company, their current STACK Meramec wells are earning rates of return at more than 100% suggesting high production volumes and low break-even costs.  In their most recent investor report, the Company announced it expects to further boost production by as much as 15%-20% in 2018 while holding spending within current cash flow limits.  Additionally, the Company is expanding drilling westward into Dewey County with the Edward Lee, a -9,725-foot lateral well with a 24-hour initial production rate of 1,857 BOEPD, 3% of which was oil cut.   Continental has also drilled a record-setting Meramec condensate well, the Lorene 1-8-5XH, producing 6,715 BOE (28% oil), which is an Oklahoma horizontal well record.  The Tres C – another record-setting condensate producer had a 24-hour IP rate of 7442 BOEPD including natural gas liquids post-processing.

Devon Energy has the top acreage position in the STACK with upwards of 670,000 net acres in the Play’s core areas of Kingfisher and Blaine counties.  A high producer boasting annual growth rates of 30%-35%, Devon remains heavily focused on STACK Meramec where it has grown production by more than 25% in 2017.  For example, in the 2nd half of last year, Devon brought online 14 wells averaging IP30 rates of more than 2,300 BOE (55% oil) within STACK’s over-pressured window.  The Company has recently announced several record-setting wells.  It’s Flenor pilot, a staggered 2-well pilot targeting the upper Meramec, came online with an IP30 rate of ~3500 BOED per well.  Also, Privott 17-H, a Meramec well in Kingfisher County had an IP24 rate of 6,000 BOEpd, 50% of which was oil.   Most notably, last fall, Devon commenced its first large-scale multi-unit pilot project, Showboat.  The project will consist of 24-wells with two drilling units and five rigs targeting the Meramec & Woodford with four landing zones.  Devon will be testing co-development and densities during the pilot.  The first production is due next quarter while a decided shift to full field development is expected sometime this year.

Marathon Oil has a large legacy position in the Anadarko Basin gained from its previous conventional drilling projects in the area.  Marathon’s infill spacing projects, Eve and Tan came online late in 2017.  The largest well, the Eve 1506, produced 992 BPD.  Another infill project, Yost, also completed in 2017 produced an average of 990 BOEPD from 6 wells.  Hansens, a 6-well infill project surrounding an existing Meramec producing well came online with an averaged IP30 rate of 915 BOED.  To date, the Company is still appraising its STACK position after acquiring PayRock Energy’s STACK acreage last year and expects to commence development operations in 2018.  Marathon also is shifting operations westward into the over-pressured oil window in Blaine County where it has a few successful wells with IP30 rates in the 1,000-2,000 BOED range.

Newfield, the originator of the STACK moniker, is also another large acreage-holder in the Play and on the move towards full development there.  The Company reports a greater than 40% return on new wells at current oil prices with one of the lowest break-even prices at $25-$30 in the Play.  Its Meramec infill pilots, Stark and Freeman, consist of 9-wells each and are producing well above 1,000 BOEPD with oil percentages above 65% after 60 and 120 days online.  Recently, Newfield announced its second record well, Hoile, drilled in eastern Blaine County, with an initial 24-hour IP of 5,100 BPOED (67% oil).  One of the more interesting STACK spacing pilots, Velta June, appears to have been testing out several new technologies.  The 12-well project targeting the upper, middle, and lower Meramec, deployed technologies such as fiber optics, borehole micro-seismic, high-resolution pressure monitoring, and DNA sequencing of formation rock.  Newfield expects the results of this testing to increase its understanding of the Meramec, well interference, and rock properties.

Summing it all up

It’s hard to believe that with all the reported STACK activity there are still fewer than 1,000 wells that have been brought online according to IHS Markit.  While it’s early in development, results have been promising, and the future for the Play looks bright.  The lower break-even costs and multiple stacked pay zones in the STACK are keeping (and attracting) investment.  While the core areas of Kingfisher and Blaine counties continue development and testing, new areas of production are emerging to the west between Blaine and Dewey counties as operators move into the STACK’s over-pressured zone.  If it’s anything like 2017, this year’s operations will be interesting to watch.

As usual, you can reach me at jparker@tellusgeospatial.com.

Sources:

Alta Mesa, Cimarex, Continental Resources, Devon Energy, Marathon Oil, Newfield, IHS Markit, KGOU.org, Fool.com

Julie Parker has a decade of experience serving the Energy industry where she became an expert in the integration and application of geospatial technologies to exploration and production projects and workflows. Ms. Parker entered the industry in 2006 when she became the first GIS Director for Chesapeake Energy, a large independent producer of natural gas headquartered in Oklahoma City, Oklahoma with operations throughout the U.S. During her tenure at Chesapeake, Ms. Parker built and lead a robust, cross-functional GIS department that gained a reputation for developing and deploying leading edge solutions for nearly all areas of the company.

 

 

 

 

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