Ok, so Oklahoma.
A few months back we took a look at the SCOOP and the STACK plays in Oklahoma, and we determined that although activity had dropped off a bit (in relative accordance with the rest of US onshore activity) there was still a lot of focussed activity going on there. Because of the recent heavy news interest in Oklahoma Oil and Gas, I thought it would be a good time to take a look at Oklahoma operations.
Oklahoma in the news
The big news item in Oklahoma, of course, has to do with the price-fixing lawsuit against, and subsequent death of Aubrey McClendon. McClendon was the longtime head of Natural Gas behemoth Chesapeake, and more recently the collection of American Energy Partners. We will take a look at some key operations of those companies.
The second big news item is that Oklahoma regulators have ordered a 40% reduction in the number of injection wells in a significant O&G area in the central part of the state as a stop gap against the assumed link between those injection wells and the increased earthquakes in the region. We’ll take a look at how that ruling might affect operations on the ground.
The third (and possibly most juicy) news item is Chesapeake Said to Weigh Sale of Assets in Oklahoma Stack Region. The terrible outlook for natural gas prices (which has Chesapeake selling $0 gas in some analysis) has forced them to look at their oil-soaked STACK acreage for cash. We’ll take a look at how Chesapeake is staked in the STACK, and how the STACK is faring.
And as a final item, E&P companies in Oklahoma are fighting against wind subsidies. This is interesting to me because of the link to out-of-state beneficiaries of the policy (and the perceived negative impact on natural gas demand). The timing on this issue seems to be appropriate due to the 7% reduction in state spending from a $1.3 billion dollar reduction on state energy tax collections. I won’t do any additional analysis on this item, but thought it was relevant to the overall discussion of Oklahoma.
Chesapeake and AEP Growth and Range
Figure 1 – Chesapeake Active Wells through December 2015, colored by trajectory, sized by 6 month cumulative gas (Source DI Production Workspace)
In Figure 1 we get a sense of the national network of natural gas success that Chesapeake has developed, largely during the McClendon years, although they continue to expand on those pathways. We see a background of vertical wells throughout the Mid-Continent, and extending over into the Arkoma Basin, as well as up east through West Virginia. But where Chesapeake has made it’s mark is the horizontal activity, and we see a clear focus on the biggest natural gas basins: in the south we see centers of activity in the Barnett, the Haynesville to its east, and the gas-rich southern part of the Eagle Ford; In the Appalachian Basin we see twin clusters of Pennsylvania Marcellus and Ohio Utica; and there are smaller bits of activity in New Mexico’s gassy slice of the Permian and the eastern part of Wyoming.
Figure 2 – American Energy Partners-Woodford wells in central Oklahoma, sized by first 6 month cumulative oil, and colored by production type (orange is oil, blue is gas) (Source DI Production Workspace)
In this figure we see American Energy Partners-Woodford wells clustered between Cushing and Stillwater. Contrary to a lot of both Chesapeake and AEP’s focus these wells are primarily oil, and with the proximity to Cushing, they couldn’t really be closer to market.
Oklahoma Injection Wells
On March 7, The Oklahoma Corporation Commission handed down a Regional Earthquake Response Plan for much of Central Oklahoma with a planned reduction of more than 300,000 barrels a day from 2015 injection volume.
Figure 3 – Source Oklahoma Corporation Commission
Figure 3 shows us that although portions of the STACK and SCOOP are less effected by the proposed reduction, AEP’s previously discussed Payne County operations (around Cushing) along with a half dozen other counties to the northeast of Oklahoma City have been added alongside the previously restricted “Western Region” along the Kansas border.
Keeping the Area of Interest from the OCC above in mind, let’s take a quick look at the portions of the STACK that Newfield has been focusing on:
Figure 4 – Source OK Energy Today
From this we can see that although the prime acreage of the STACK is within the OCC’s AOI, it mostly lies outside of the central reduction zone, and if there are Arbuckle Wells, they haven’t been shown on this map. One can speculate that the water cut from the often-targeted Meremec Formation is low enough that it’s of markedly less concern – in fact Felix Energy recently claimed that they had no produced water from STACK operations.
Figure 5 – Well Count for Canadian, Kingfisher and Blaine Counties by operator, Source (DI Analytics)
In Figure 5 we see total well counts for the big 3 counties within the STACK. The three largest Operators are Devon, Cimarex and Linn. Frankly all of these operators would be greatly augmented by acquiring The Chesapeake holdings since they all have infrastructure and knowledge of the geology on their side.
While current low natural gas prices will likely limit E&P opportunities to build upon Aubrey McClendon’s tremendous legacy, the prospect of an oil price rebound bodes well for many Oklahoma plays. The expansion of storage capacity in Cushing, as well as the new ability to export domestic U.S. crude to foreign markets from Cushing, meaning that Oklahoma’s central location, favorable geology, and business leadership guarantees that Oklahoma is ok.
What do you think? Leave a comment below.
INTRO TO THE SALE
The W.T. Waggoner Estate Ranch is a behemoth piece of Texas land with a legacy to match. With over half-a-million acres spread over six counties, it’s reportedly the largest U.S. ranch within one fence. The sale of the property was mandated by a judge after the Waggoner heirs could not agree how to liquidate, and on February 9 NFL Rams’ owner Stan Kroenke agreed to purchase the ranch. Listed at $725 million, the ranch is one of the top cattle ranches in the country and is also home to esteemed quarter horses, polo fields, and several lakes. The property rests in the North Central Plains region of Texas.
But it’s not just a scenic cattle ranch. The Waggoner Ranch is major producing oil and gas asset with potential for more exploration.
Image source: http://www.bloomberg.com/graphics/2015-famous-texas-waggoner-ranch-for-sale/
Although the sellers wish to preserve the rustic character of the property, there’s plenty of room to develop new oil and gas wells throughout. There are already a reported 1200 oil and gas wells already on the property that have successfully been incorporated into the landscape. In addition to the massive existing production, it’s the opportunity to explore in the future that should have E & P’s closely monitoring the sale. The new buyer will reportedly be receiving 42% of the mineral estate, and the Waggoner family will (very wisely) retain 25% mineral interest in the land.
To look at what reservoirs are in play in the area, we did a simple production search in DI Desktop. We limited our search to active oil wells in the six Texas counties Waggoner Ranch covers: Archer, Baylor, Foard, Knox, Wichita, and Wilbarger. We then combined results based on name alone for the eight reported reservoirs with the highest well count (excluding those where the reservoir was not reported).
Active oil wells in the vicinity of Waggoner Ranch. Colored by reservoir. Red represents all other reservoirs. As seen in the previous table, wells with production from the Cisco (green) and Gunsight (dark gray) reservoirs are most numerous.
A look at an oil field in Wilbarger County. Production bubbles are based on daily oil. Grayback is 12.5 miles SSE of Vernon, TX. Grayback is slightly east of Zacaweista Ranch, one of the three subranches W.T. Waggoner established for his children. The well highlighted is a relatively new vertical drill targeting the Coleman Junction formation. Many of the oil wells on the ranch are historical, dating back to the 1930s.
Active oil wells with first production after January 1, 2010 colored by drilling trajectory. Twenty-three horizontal wells have been drilled which meet this criteria. Bubble size represents daily oil. The big producer to the north is the Fargo Unit 4102H (API 42-487-33072) operated by Tradition Resources. The reservoir is reported as ‘consolidated’.
A historic map of oil and gas fields in the North Texas Area (1951)Source: Petroleum Engineering Study of K.M.A. reservoir, Southwestern Part K.M.A. Oil Field, Wichita and Archer Counties, Tex. Rollie P. Dobbins, Marion L. Ayers, and Roger E. Lewis. Bureau of Mines, Report of Investigation 4892 (June 1952). http://digital.library.unt.edu/ark:/67531/metadc38582/m2/1/high_res_d/metadc38582.pdf
A correlation of generalized geologic column and electric log, Wichita and Archer counties, Texas. Source: Petroleum Engineering Study of K.M.A. reservoir, Southwestern Part K.M.A. Oil Field, Wichita and Archer Counties, Tex. Rollie P. Dobbins, Marion L. Ayers, and Roger E. Lewis. Bureau of Mines, Report of Investigation 4892 (June 1952). http://digital.library.unt.edu/ark:/67531/metadc38582/m2/1/high_res_d/metadc38582.pdf
Wells in the Cisco formation target Late Pennsylvanian fluvial and deltaic deposits. The geology is defined by the Electra Arch (center) and the Red River Arch (above), which runs east west across the northern border of Wilbarger, Wichita, and Clay Counties. “Electra” refers to the city of Electra, which is named after W. T. Waggoner’s well-known daughter. Source: http://www.waggonerranch.com
A north – south geologic cross section. Both sandy beaches and deltaic deposits are present. The Electra Arch complex is a carbonate platform. Source: http://www.waggonerranch.com
Using DI Desktop, we performed a production search and then grouped by operator to see what companies were active around Waggoner ranch. Layline Energy was the top, with 1095 active oil wells. Layline focuses on acquiring and improving mature onshore oil fields (Bloomberg). None of the majors had active oil wells in the six counties.
Oil production statistics for the 10 most active operators in the six counties touching Waggoner Ranch (based on active oil well count)
Pipeline connectivity surrounding Waggoner Ranch. Nustar, Plains, Phillips 66, and Enterprise pipelines convey the crude. Lantana Midstream and Atmos carry the natural gas. The most connections are present around the dense oil wells in Wichita County, but the ranch only covers the western edge there
Historical production from the Cisco reservoir, including both active and historical oil wells across Archer, Baylor, Foard, Knox, Wichita, and Wilbarger Counties. Total production peaked around 1965, with the well count beginning to decrease around 1990
A type curve for Cisco producing oil wells. Year 00 is the first year of production. Water production closely mirrors oil production. A steeper decline is observed for years 00-19. After about year 43, year over year production levels out somewhat
The sale of the Waggoner ranch is something to keep a keen eye on. The new land owner might be eager to further expand the scope of oil and gas activity on their new property. With some 510,000+ acres in Texas, operators should have a game plan ready to move fast and get the best acreage the new owner may be willing to lease. Despite the maturity of the area, new vertical wells are being drilled all the time and providing solid production.
Special Thanks to Ashley Justinic.
What do you think? Leave a comment below.
Age demographics do not care about the price of oil. Whether oil is at $100/barrel or at $30/barrel, babies get born, people age and pass away, and when they do, their assets get passed on to their families, dear friends, favorite charities, or alma maters.
This could be the great, untold story of the Great Crew Change – the massive transfer of mineral wealth that is happening each and every day.
However, this article is not about that.
Instead, we’re going to look at how the next generation of mineral wealth might be identified.
The Current Unconventional Wisdom
In the midst of the economic pain that all sectors of the fossil fuel are enduring, virtually all discussion has centered on how a price recovery will be shaped by the massive portfolio of unconventional wells that we have drilled.
But, how will DUCS (drilled, uncompleted wells) moderate price appreciation as independent operators gauge their margins and IRRs and model when and where to complete and bring production into a precariously balanced market?
Who has the available cash, or the access to financing, to engage in targeted acquisitions of seemingly attractive unconventional assets? Given the volatility in prices, how will they be allowed to book their assets, especially if much of their acquired acreage is in that never-never land between proved producing and proved undeveloped. How will banks that continue to finance energy clients set their loan covenants with their borrowers? How has the pace of innovation to best practices been slowed by the downturn in activity—since each well is an experiment that delivers and amplifies the knowledge base of the industry?
And, most importantly, how do you model the price of oil—or at least constrain your price risks—given the huge numbers of independent variables that affect both demand and supply? If it’s that difficult to model, how do corporate risk officers control for the financial risk to their enterprises?
The Conventional Option
Maybe you don’t. Maybe you target your acquisitions toward conventional assets by focusing on economic drivers that require less financial engineering and which are more predictable.
The universe of players is almost infinite in its complexity, ranging from financially responsible large companies to salvage buyers who may be looking for pre-plugging behind pipe potential.
Therefore, the number of economic models will be dizzyingly varied, but some of the analysis processes used to identify opportunity can be constrained.
Let’s set the following problem in terms of a very modest acquisition budget: I want to identify all producing leases in Texas that are producing between 20-50 barrels a day and which will have operating expenses below $10,000/month. I choose these constraints because operators with these metrics may be more likely to sell their producing asset base.
Since cost information is notoriously hard to compile, we’re going to use the number of active wells as a proxy for operating costs, and so we have limited the query to currently producing leases with 1-4 active wells that are producing 20-50 BOPD.
Here’s my map, courtesy of DI Desktop allocation option invoked)—
In order to get a sense of where the best opportunities are, we’ve put them in a scatter plot and plotted, by Texas county with the EURS for each operated property.
The scatterplot quickly illuminates the population of operated properties for each EUR level ( EUR=300,000BBL highlighted in turquoise), and which counties have rich spectra of EUR values (example in vertical pink box).
If a prospector is interested in KS operated properties making between 100-500 BOPD with 5 or less wells and with TD’s less than 6000’, here’s the opportunity space:
And to constrain my apparent opportunity set, I can see how thoroughly the areas that I’m interest in have been leased.
These are but two examples of the kind of opportunity identification that acquisition minded operators or private equity interests could consider.
There are many advantages to acquiring maturing conventional properties.
- The cost structure is known
- Any development drilling is cheap relative to horizontal drilling and completion operations
- The reserves are proved producing and therefore are immediately bookable
- They can be more nimbly managed in a time of price volatility
A final point. The decline profile of unconventional wells is severe.
This set of type curves by year in the Bakken shows the behavior
Compare the Bakken decline behavior above to the performance of this well in the Utah hinge line play:
Well-chosen conventional production has a longer producing lifetime, and will deplete the reserve base more slowly than unconventional properties will. And although it’s not as exciting on the front end of $100 oil, it’s way less painful than producing 50% of your reserve base when prices are massively depressed.
What do you think? Leave a comment below.
Last Thursday when we published our latest DI Index of New Production Capacity (NPC), a relatively large increase in new (month over month, national) permits filed (18%!) raised the question, “what’s up with permits?” So we dusted off a few of our various spyglasses and microscopes in the DI Gallery and looked into the increase.
First, we took a look at the DI Index itself.
Permits aside, NPC – which is a measurement of oilfield activity that accounts for the type, size and placement of active rigs in order to give a more accurate prediction of what today’s drilling activity will ultimately generate in production – for the month of December was down a little bit verses November, as has generally been the case throughout the year. Our daily DI Rig Count, has also been showing a downward trajectory.
When we drilled down into some of the monthly basinal and geographical reports we didn’t immediately see a spike in permitting activity in, say, The Permian Basin or the Eagle Ford. (We do have a neat perspective on Bakken activity this month which you should check out).
DI Activity Maps
Next we turned on our handy DI Activity Maps, and looked at our 30 day permitting heatmap to look for any weirdness.
Clearly the areas that we expect to see activity are burning brightly – the northern counties in the Eagle Ford, the Midland and Delaware basins, Colorado’s Niobrara, the Bakken in North Dakota, the Appalachian plays. But California looks like it has some new heat, as does Wyoming.
A quick check of new drill permits (as opposed to re-entries) in California showed a rather sizable spike in Kern County (from 749 in November to 1284 in December) adding 535 permits in one month, which accounts for a large portion of that 18% M/M increase. A recent county ordinance to fast-track permitting may explain that spike. In fact, in both November and December, Kern County had the highest number of permits of any county in the country by far, so this increase has a big impact on the national total.
Mapping the new Kern County permits shows that the great majority are within the confines of known fields. Kern county also had 422 re-entry permits filed in December, so most of this activity is just more straws into the milkshake.
Converse County, Wyoming (Niobrara) also had a significant jump in permits – from 53 in November to 153 in December. In this county, a large number of permits look to have been filed in the second half of December in a few select leases.
What do you think? Leave a comment below.
If you’re a regular reader of this blog, I don’t have to tell you that Daily Average production numbers can play a critical role in analyzing a well. Often times, operators will not choke back and instead turn production on full blast to impress investors. Looking at Daily Average production can help to get a more accurate view of the well’s performance. Additionally, if you have enough history, looking at the Daily Average over a period of time can give you a good idea of the well’s decline.
However, reporting becomes an issue when trying to compare apples to apples. Some states report the number of days (or “Days On”) within the month wells produce, while others do not. As a result, Daily Average calculation varies in DI Desktop. Specifically, AZ, CA, CO, FO GULF, MT, ND and NM report the number of days wells produce. For all other states, the Daily Average in DI Desktop is derived by using the number of days in the month.
To utilize the “Days On” feature when searching any of the states listed above, first go to the “File” menu at the top left of the DI Desktop window and select “Preferences.” After the preferences window appears, click the “Use ‘Days On’ to calculate Daily Avg.” checkbox.
Next, click the “Grouping” icon.
Then, click the “Production Formatting” tab and select the “Daily Average” radial under the “Production” heading.
To see how many days were used to calculate each well’s production numbers, click the “Details” tab.
Alright, that should be enough to make you dangerous. If you ever need any help walking through this or any other workflows, call our Support line at (888) 477-7667 ext. 3. We would be happy to help you get the most out of your subscription!
Now it’s your turn. What do you think is the best way to get an accurate picture of a well’s ultimate performance? Leave a comment below.
Drillinginfo was on a mission to raise NAPE attendee’s oil & gas IQ this summer with insightful presentations and the release of DI Pro. This new package is comprised of DI Analytics, DI Geology, DI Land and DI Desktop. Those who attended the presentations not only got a first look at the new features, but examples of how they can improve your workflows and help oil & gas professionals make smarter, faster decisions.
Colin Westmoreland speaking at Drillinginfo’s Summer NAPE booth
If you’ve ever been to a Drillinginfo NAPE booth, then you know we can’t help but have a little fun. This year we welcomed Mentalist Jon Stetson, who would read our participant’s minds before each presentation. He was so dead on he even put his own money on the line if he was wrong…although he never was.
Mentalist Jon Stetson on the Drillinginfo stage
Come see what we have in store for Winter NAPE at booth number 2509 on February 5-8, 2013.
If you’re interested in learning more about what DI Pro or any facet of Drillinginfo has to offer, please contact your sales representative.