Almost 400,000 net mineral acres are currently up got grabs in the hottest play in the U.S. 685 tracts of land are up for bid in the Delaware Basin, Midland Basin, Central Basin Platform, and Ozona Uplift (Permian Basin) through the current University Lands lease sale (Marketed: More Than 410,000 Net Acres, Texas State Leases; Oil and Gas Investor), but not all acreage is created equally.
I want to take this opportunity to make sure all of my oil and gas industry friends know how to quickly evaluate existing and potential production using engineering and geological data available in Drillinginfo’s web platform. Bids for University Lands leases are due September 20th, so there is time still to determine if the available acreage fits your company’s criteria and objectives.
The Permian Basin continues to provide lucrative opportunities, but productivity can vary so much according to the geology. I will quickly look at historical production within my leases of interest, determine what kinds of wells exist here, identify from which depths and geologic zones these wells are producing, and then will analyze offset well production in a similar fashion.
In Figure 1 you can see the lease outlines (loaded via shape file into the Drillinginfo web platform) relative to a couple of activity heat maps. Some of these leases for sale are in core parts of the Permian Basin, and we can see that rigs are currently drilling very close to some, but many other leases for sale are on the fringes of the Delaware and Midland Basins.
Figure 1 and 2: University Lands leases shape file (green) overlying DI-generated heat maps of (top map) leasing activity for the past 90 days and of (bottom map) permitting activity for the past 90 days in the Permian Basin area, plus current rig locations as of 8 Aug. 2017 (from Drillinginfo web platform)
I’m particularly curious about the southeastern Midland Basin, since I’m not very familiar with acreage out here. When I constrain my production search using the lease polygon outlines in Crockett, Irion, and Schleicher counties, I learn that the vast majority of wells within these leases are vertical wells; all are classified as oil or gas wells; and over 70% of these wells are not active. Additionally, most are targeting the Canyon and Ellenburger, and the highest First 24mo Peak BOE is almost 65,000 bbl (a vertical Ellenburger well).
Figure 3: A production search within leases of interest shows that the majority of existing wells here are vertical wells, many target the Canyon and Ellenburger (according to reservoir reported by operators), and none exceed 65,000 bbl BOE in their first 24 months. (from Drillinginfo web platform)
By referencing the University Lands’ Lease Sale 128 Tract List’ document I can see that in Schleicher County for example, blocks 53-57 have sections up for lease, and there do not appear to be any depth restrictions. I can search for all production that’s reported to these blocks of interest in order to generate a larger, and still very relevant, population of wells. Of the 39 horizontal wells in this population, the majority target the Canyon. Of the 300 vertical wells in this population, the reported targets are many, but the highest First 24 BOEs belong to what operators have reported as the Canyon and Leonard.
Figure 4: Oil and gas wells (colored by drill type and sized by First 24 BOE (bbl)) located within the Schleicher, Crockett, and Irion County blocks of interest, where sections are available for bid/lease according to ‘Lease Sale 128 Tract List’ document. The abstracts/sections layer and wellbore trajectories layers are turned on in map on left. Plot on right shows these wells’ reported reservoirs vs. measured depths. (from Drillinginfo web platform)
After filtering to horizontal oil wells with perforated interval length less than 6,000 ft that have produced for 9 months or more from the “Canyon 7520” reservoir (excluding wells in ‘University Unit’), I use the probabilistic decline curve analysis tool in the web application to generate a type curve and calculate EUR. Using the Arps equation, no segmentation, and setting the minimum acceptable monthly rate to 1 bbl/day, the model calculates a 90% probability of a 36,615 bbl EUR for oil, with a 10% probability of producing 44,962 bbl oil, and a best fit EUR of 44,525 bbl oil. If perforated interval lengths range from about 3,600-5,000 ft, what might it cost to drill and complete a well in this formation?
Figure 5: Probabilistic EUR model input wells and output. Black lines forecasting production (top right) represent P10, P25, P50, P75, P90. Input data is from horizontal wells with perforated interval less than 6,000 ft in blocks 53-57 producing for 9 months or more from the Canyon 7520 (reported reservoir). (from Drillinginfo web platform’s Decline Curve Analysis tool)
Next I would filter to Wolfcamp wells in this area to see the depths of these wells, perforated interval lengths, and what kinds of EURs I might expect from those wells specifically. In this area, our internal team of geologists has determined that most of the Wolfcamp wells here land in the Wolfcamp B specifically (you can log in to the Drillinginfo web platform and filter to Play Assessment wells to explore further), and the highest Peak BOE is 42,859 bbl on a 7,098 ft perforated interval landed relatively deep in the Wolfcamp B.
To look quickly at completions, I filter to all horizontal wells in the blocks of interest that have been spud since Jan. 2010 and investigate perforated interval lengths and proppant per foot usage. Operators are continuing to increase proppant amount used per foot by using high total proppant volumes in shorter laterals (at least in 2014 compared to 2012) with mixed results.
Figure 6: All horizontal wells spud since 2010 within blocks of interest. In map at left, wells colored by perforated interval length, sized by Peak BOE (bbl). In chart at right, spud date vs. total proppant shows a slight decrease in total proppant used post-2013, but shorter perforated interval lengths on average, thus higher proppant per foot usage. (from Drillinginfo web platform)
After investigating existing production and completions in and around my leases of interest, do these wells produce enough oil and gas to justify further investigation and modeling? If so, I’d move into DI WellCast for economic analysis. If not, it’s time to move on to the next area of interest and repeat the process.
We’re in the business of saving our customers time, energy, and money. After completing my analysis, I could actually share my saved workspace with anyone in my organization in order to facilitate more productive conversations and easier decision-making. If you need to evaluate an area of interest quickly and would like some guidance, please let us know!
You can contact me, your sales rep, technical rep, customer support, email@example.com, or visit our booth at NAPE August 16-17th in Houston.
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