Rosehill Resources has published three press releases in the past two months detailing their Q4 southern Delaware Basin acquisitions. We know that they expect to drill upwards of 400 horizontal wells targeting primarily the Wolfcamp A, Wolfcamp B, and Bone Springs formations in Pecos County, TX (https://www.rosehillresources.com/news-media/press-releases/detail/22/rosehill-resources-inc-surpasses-11000-net-acres-with), and that their new neighbors include Jagged Peak Energy, Diamondback Energy, and Parsley Energy. (https://www.rosehillresources.com/news-media/press-releases/detail/15/rosehill-resources-inc-to-significantly-expand-its; Figure 1). In Pecos County, the Drillinginfo Geology team has determined that operators have landed a majority of recent horizontal wells in the Wolfcamp A and B zones. Using the DI Geology team’s Delaware Basin Play Assessment project, we also see the Wolfcamp A and B thicken through this area to the southeast (Figure 2). Rosehill Resources noted that the “contiguous acreage position enables 7,500- to 10,000-foot laterals, which can significantly improve well economics” (https://www.rosehillresources.com/news-media/press-releases/detail/21/rosehill-resources-inc-completes-initial-delaware-basin). Since many operators are increasing both lateral footage and proppant usage in this area, I can use the Drillinginfo web app and DI WellCast to compare the economics of various D&C strategies in this interesting part of the Permian Basin.
Figure 1: Operators mentioned in press release’s well locations in the southern Delaware Basin. (Drillinginfo Web Platform)
Figure 2: Isopach from Wolfcamp A top to Wolfcamp C top, interpolated using B-Spline. Wells with picks used for interpolation are shown in white. (DI Play Assessment – Delaware Basin – October 2017 Release – mapped using DI Transform software)
The DI Geology team defines primary landing zones (“primary” meaning 60 percent of completed intervals or more landed in a single zone) for horizontal wells by relating deviation surveys to DI Play Assessments structural models. This is particularly useful in areas like the Permian Basin where production reporting is infamously vague. Figure 3 shows that the majority of horizontal wells that can be tied to a primary zone landed in the Wolfcamp A or Wolfcamp B, and that the top producers are all Wolfcamp A or Wolfcamp B wells.
To drill down further, I selected only Wolfcamp A and Wolfcamp B wells and compared perforated interval lengths to both proppant usage and production (Figure 4). We see three populations defined in the data: horizontal wells with perforated interval lengths around 4,500, 7,500, and 10,000 feet. Proppant-per-foot usage is relatively high in this area, so I filtered to wells where 1,500 to 3,000 pounds per foot of proppant were used for the first treatment (frac) job. The goal is to be able to compare Wolfcamp A and Wolfcamp B wells with similar lateral lengths and proppant usage, and to evaluate the potential return on more aggressive versus more conservative drilling and completions strategies.
Figure 3: DI-defined Geology Zones vs. First 12 BOE, sized by perforated interval length, showing horizontal wells that can be tied to a specific primary zone. (Drillinginfo Web Platform)
Figure 4: Only Wolfcamp A and Wolfcamp B wells with 1,500-3,000 lbs/ft proppant used are shown. Note three populations defined in the data: perforated interval lengths around 4,500 feet, around 7,500 feet, and around 10,000 feet. (Drillinginfo Web Platform)
Figure 5: Wolfcamp A (orange data points, outlined in green in cross-plot) groups selected in cross-plot and highlighted in green on map. X-axis perforated interval length and ranges from 3,860 to 10,155 feet. Y-axis is proppant per foot and ranges from 1,500 to 3,000 lbs/ft. Data points are colored by geology zone and sized by First 6 BOE (24,170 to 174,930 Bbl). (Drillinginfo Web Platform)
Figure 6: Wolfcamp B (blue data points, outlined in green in cross-plot) groups selected in cross-plot and highlighted in green on map. X-axis perforated interval length and ranges from 3,860 to 10,155 feet. Y-axis is proppant per foot and ranges from 1,500 to 3,000 lbs/ft. Data points are colored by Geology Zone and sized by First 6 BOE (24,170 to 174,930 Bbl). (Drillinginfo Web Platform)
The Wolfcamp A short laterals (six wells in group) have an average perforated interval of 4,542 feet and average proppant-per-foot usage of 1,984 lbs/ft, compared to Wolfcamp B short laterals (seven in group) whose average perforated interval length is 4,384 feet and average 2,303 lbs/ft of proppant (Figures 5, 6, and 7). The Wolfcamp A medium laterals group (10 in group) averages 7,635 feet for perforated interval length and 2,335 lbs/ft of proppant, while the Wolfcamp B medium laterals group (five in group) averages 7,164 feet for perforated interval length and 2,481 lbs/ft of proppant. Lastly, the Wolfcamp A long laterals group (seven wells in group) has an average perforated interval length of 9,926 feet and averages 2,388 lbs/ft of proppant. There were no long Wolfcamp B laterals to compare to the Wolfcamp A long laterals group.
In order to estimate the IRR for these five populations of horizontal wells, I created a type curve and estimated well costs for each group. Using DI WellCast and my API lists, I fit decline curves to every group using both oil and gas production data, generated EUR estimates (Figure 7), and saved the curves. To estimate differences in drilling and completions costs between groups, I assume a cost of 10 cents per pound for proppant (most of these wells use sand, according to the DI Engineering Explorer completion database) and estimate $700 per lateral foot for drilling and other completion costs. In calculating single-well economics in the DI WellCast tool, I set oil price to $55/bbl and adjusted the drilling and completion costs, otherwise leaving default values, though any of these parameters can be adjusted (Figure 8). The only IRR lower than 25 percent turned out to be the Wolfcamp long laterals group, whose D&C costs were of course quite high. If I drop the D&C cost for the Wolfcamp A long laterals group from $9.3 million to $8 million, then my IRR increases to 25 percent. One of the ~10,000-foot wells in the group was truly outstanding, but in this analysis, there seems to be relatively high risk and uncertainty in executing these more expensive wells. Both Wolfcamp B short and Wolfcamp B medium lateral groups had high IRRs, as did the Wolfcamp A short lateral group.
Figure 7: Pecos County Well Groups Summary Table. Source data from Drillinginfo Web Platform, plus assumptions, as explained above.
Figure 8: Single-well economics model example using the Wolfcamp A long laterals group and type curve. Default parameters used, except for oil price ($55) and drilling and completion costs ($7 million and $2.3 million, respectively). (DI WellCast)
While there are quite a few standout horizontal wells in the Pecos County acquisition area – particularly wells that landed in the DI Geology-defined Wolfcamp A and Wolfcamp B – there is some notable risk in drilling and completing relatively long laterals with large proppant volumes. Fortunately, the IRR on most of these higher-proppant-per-foot Wolfcamp A and Wolfcamp B wells in Pecos County exceeds 25 percent based on my basic analysis. I’d be interested to see how nearby Reeves County Wolfcamp A and B wells compare, particularly those with long lateral lengths and high proppant usage. Regardless, with a total acquisition cost of less than $120 million and the potential for 400 new horizontal wells (https://www.rosehillresources.com/news-media/press-releases), it sounds promising.
Kenya – Pate 2 – L4 – Operator Zarara plans to start drilling in January 2018
Zarara Oil & Gas is expected to spud the Pate 2 appraisal well in January 2018. The environmental licences for the planned drilling campaign were approved by Kenya’s National Environment Management Authority (NEMA) in October 2017 and will be valid until July 2019. The Great Wall Drilling Company Ltd has been contracted to carry out drilling operations; the GWDC 190 land rig is likely to be utilized. Norwell Engineering is progressing with the planning and design of the drilling programme, which currently involves Pate 2 & 3 and the option of two additional appraisal wells.
Figure 1: Pate appraisal well location
The estimated total project cost stands at approximately US$ 15.7 million. Pate 2 has a 4,600m PTD (to be a vertical well), which Zarara has estimated will take ~120 days to drill, test and complete. The primary target is the Kipini Sand Group; a fluvial and deltaic facies, which has been described as poorly sorted and unconsolidated, but has also been reported to have good net log porosity. A deeper Upper Cretaceous Kofia sand, which was penetrated by the offset Kofia 1 well, may also be a secondary target. The well is appraising the Pate gas discovery, in the Lamu Basin, which was drilled by the Pate 1 well in 1970. Pate 1 reached a 4,175m MD and encountered an over-pressured 10m gas-charged, Lower Eocene-aged sand (Basal Kipini reservoir) at TD. It was targeting a dip closure on the SW extension of the Mararani-Dodori anticlinal trend, with Lower Tertiary and Upper Mesozoic objectives, which had previously been encountered in the Dodori 1 well (1964, small shows and traces of bitumen in the Palaeocene). However, due to technical problems during drilling, Pate 1 was neither logged nor tested and failed to fully penetrate the reservoir section. Zarara is a wholly owned subsidiary of Midway Resources International and holds a 75% WI and operatorship for the L4 and L13 licences; the remaining equity is held by SOHI Gas Lamu Ltd (a wholly owned subsidiary of Swiss Oil Holdings International Inc) (15%) and NOCK (10%). The interest held by these companies is free-carried until final approval of planned commercial production. However, Zarara has negotiated a Heads of Agreement for the eventual acquisition of the 15% interest from SOHI Gas Lamu Ltd.
Figure 2: Planned well locations Q1 2018
US crude oil stocks decreased by 1.9 MMBbl last week. Gasoline stocks remain unchanged, while distillate inventories increased by 0.3 MMBbl. Yesterday afternoon, API had reported a crude oil withdrawal of 6.4 MMBbl, alongside a gasoline build of 0.9 MMBbl and distillate withdrawal of 1.7 MMBbl. Analysts, were expecting a more modest crude withdrawal of 2.1 MMBbl. The most important number to keep an eye on, total petroleum inventories remained unchanged and maintained levels from the week prior. For a summary of the crude oil and petroleum product stock movements, see table below.
US production was estimated to be up 13 MBbl/d from last week per EIA’s estimate. Lower 48 production increased 20 MBbl/d while Alaska production decreased 7 MBbl/d. Imports decreased by 25 MBbl/d last week to an average of 7.9 MMBbl/d. Refinery inputs averaged 16.8 MMBbl/d (199 MBbl/d more than last week), leading to a utilization rate of 91.3%. The report is bullish due to crude oil inventory withdrawal. Prices are up, with prompt month WTI trading up $1.01/Bbl at $57.84/Bbl.
Prices traded in the $55-$57/Bbl range last week and edged closer to $57/Bbl on Tuesday following the bullish API report. Prices extended their gains into Wednesday following news on Keystone cutting deliveries by at least 85 percent through the end of November due to a 5,000 Bbl leak in South Dakota, along with an expected crude inventory withdrawal. WTI reached $58.05/Bbl earlier in the day, the highest since July 2015.
Prices are being pulled in both directions ahead of the Nov. 30th OPEC meeting in Vienna. The consensus in the market is that OPEC will extend the production cuts beyond the March 2018 expiration date. However, Russia’s unwillingness to join the possible extension is causing some skepticism around OPEC’s extension to supply cuts and what it would look like without Russia’s cooperation. In addition to Russia’s stand on supply cut extensions, rising Iraqi crude production has also complicated the dynamic in the market. Iraq crude exports rose to record highs in November (150 MBb/d higher than October) as Iraq is trying to offset the crude export disruptions from the Northern region Kirkuk to the Turkish port of Ceyhan.
OPEC’s efforts in balancing the market is getting some help from declining Venezuelan production and the uncertainty around countries production levels moving into next year. However increasing production from Iraq, non-OPEC producers and the US would offset and could overturn the loss caused by Venezuela. OPEC will be in a tight spot ahead of the meeting, as the market has increased their bullish bets on crude futures with expectations of a supply cut by the group. Any bearish news from the meeting would send the market into a selling spree and send prices into a downward spiral. While any bullish news and a price rally will incentivize US producers to hedge production at higher prices and increase production rapidly in addition to the possibility of higher Iraqi and Libyan production.
The market has now held over $49.00/Bbl for over a month, establishing that as the low end of the new range. It is still critical regardless of the outcome from the OPEC meeting, that high compliance with production quotas and realization of the demand growth projected by IEA will need to occur to reach the five-year average inventory levels. Without inventory normalization, the price recovery will not be sustained. Drillinginfo expects the trade to return to the previous range $50-$55/Bbl in the coming weeks as fundamentals start to settle back in.
Please find the updated Drillinginfo charts on the link below:
Petroleum Stocks Chart
Those of us who have focused our professional skills on domestic US oil and gas exploration and production sometimes lose sight of how actively international oil and gas concessions/properties/interest are trading hands.
Below is a quick collage of international assets transactions
Collage of international assets transactions
Since 1/1/2013 there have been 8677 asset transactions worldwide in which a working interest/participation did/would have changed hands. Since only 6% of these were cancelled, it’s fair to assume that the international oil and gas asset
market is active and reasonably healthy.
With about 6 more weeks left in this year, with no new deals 2017 will close out at the second highest level of ownership deal flow (transactions + pending deals) since 2013.
Graph of international asset transactions by year
We would expect the pace of international asset transactions to maintain this momentum as oil and gas pricing stays relatively stable (or increases) and especially if petroleum ministries (national and provincial) begin to incentivize investment of exploration and development CAPEX.
The largest transaction by acreage amount was Petronas’ 5/20/2014 purchase of STR Projetos e Participacoes Ltda’ 37.5% interest in lightly drilled Blocks 9 and 11… located NNW of Malakal and including Khartoum.., South Sudan [total acreage =68.8 million acres, or a piece of land measuring about 330 x 330 miles.
That’s a big chunk of territory.
Map of Petronas’ interest in Blocks 9 and 11
For perspective, this block of acreage would contain the entirety of the Permian Basin.
Map of the Permian for comparison
This transaction dwarfs any of the other 26 Petronas interest purchases ….they
must have seen a lot of East African Rift potential here, since only 6 wells have been drilled in the blocks, all of them are dry holes, and just one well had oil shows.
More recently, INEOS was very active in 2017, transacting for approximately 740,000 acres of mostly gas/gas & oil reserves.
Map of INEOS activity 1
Map of INEOS activity 2
INEOS’ gross 3,878,000 acre position (all years) is all European and is highly concentrated in the UK, and represents participation interests ranging from 10% to 50%. About 2/3 of the acquired interests are offshore,
Chart of INEOS acreage by country
There appears to be little correlation between acreage block size and % interest purchased, so it looks like INEOS is making very focused acquisitions.
Chart comparing Interest Purchased to Area ONSHORE
Chart comparing Interest Purchased to Area OFFSHORE
Our International subscribers can use all the information in Asset Allocations to
determine the patterns of buyers and sellers, and use the Block Card to assess
where buyers and sellers have other country assets that you should know about.
Example of a Block Card in the DI International Web App
One thing that has always been drilled into my head is that I must consider each formation separately because no two geologic settings are the same. In my current position at Drillinginfo, I get the privilege of looking across multiple formations while speaking to different people every day. One thing that I noticed is that no matter where I looked, the trends in completions always seemed to be the same. As illustrated in Figure 1a, the trend is undeniable: Over time, operators have been consistently pushing the proppant and fluid concentrations up and to the right. When I looked at this trend across all the major basins (Figure 1b) the theme of “up and to the right” seemed to hold true but with some subtle differences in slopes and ratios. Throughout my analysis I found this observation to largely hold true; at the surface, most completions appear to be similar across each formation. It takes a closer look to understand how they are different.
Figure 1a – Average proppant (top) and fluid (bottom) per lateral foot over time.
Figure 1b – Average proppant (purple) and fluid (red) per lateral foot over time by basin
To fully explore the differences, or lack thereof, in completions across all formations in all basins would require a much longer post that I was willing to commit to, so I decided to focus my exploration in the area with the most activity, the Permian Basin.
• Ensure that each geologic formation can be said to be different from all the others
• Understand and account for the change in lateral lengths across each geologic formation
• Examine the proppant, fluid, and additive usage across each formation to identify potential differences
• Aggregate my findings to determine what, if any, conclusions could be drawn
Understanding Geologic Differences
As obvious as it sounds, I first had to be sure that operators were completing multiple formations, and which ones. Figure 2 gives a breakdown of the top producing intervals in the Permian since the start of 2013 (the left side is colored to indicate the contribution by each side of the basin). As simple as this may sound, in Texas reported producing reservoir can be extremely vague and most often is no help at all in identifying where wellbore has landed (see right side of Figure 2). But, I was fortunate enough to capitalize on the hard work of Drillinginfo’s geologists and quickly understand exactly which formations to explore further.
Figure 2 – Left, count of wells in each geology zone colored by play. Right, count of wells in each geology zone colored by reported reservoir – Since 2013
The main trends here seem clear: The Midland Basin is dominated by the Wolfcamp B, while the Delaware Basin gets most of its production from the Wolfcamp A, with the Bone Spring 2nd Sand not too far behind. After those formations the differences become much smaller. With the end goal of being able to create meaningful visualizations, I decided to focus on the top nine formations by count, so everything to the right of the Wolfcamp D in Figure 2 was excluded.
The next step was to verify that these are distinctly different geologic formations. Once again thanks to the hard work of DI’s geology team, I was able quickly examine the average log curve across each interval. Figure 3 shows the distribution of the log curve values for each geologic interval. It is immediately clear that there is a distinct change in resistivity values across each formation. From there the differences become slightly more subtle, however, there are still distinctions, especially when you compare the shale formations to the sands and carbonates.
Figure 3 –Distributions of average log curve values by formation. Black lines indicate the 95% confidence interval for the mean.
Accounting for Lateral Length Effects on Production
Having confirmed that each formation is different from the other, I started to look deeper into the completions of these intervals. First, I looked at the lateral length for wells drilled from 2013 to 2017 relative to each of these formations (Figure 4). From this chart it can be seen that the Lower Spraberry and Wolfcamp sections lead the way as far as lateral length per well, with the other five formations having distinctly shorter horizontals on average. However, the range (max to minimum lateral length) is very similar for each formation. Because many factors can go into determining the lateral length of a well, I did not want to consider it as a variable in determining completions differences; however, this view made it clear that it was something that I needed to normalize for. After all, pumping a million pounds of proppant into a 5,000-foot lateral is not nearly the same as pumping the same amount into a 10,000-foot lateral.
Figure 4 – Lateral length by formation
Examination of Proppant and Fluid Use Across Formations
The two largest variables in completions behind lateral length (keeping in mind that all subsequent charts from here on are normalized to lateral length) are proppant and fluid usage. These two materials generally account for more than 95% of the entire frac slurry. In Figures 5a and 5b the theme of subtle differences once again is evident. When looking at the mean amount of proppant (Figure 5a), the Lower Spraberry has been completed with the most proppant and the Bone Spring 3rd sand has used the least. There is a slight trend that probably would not meet the standards for “statistically different” as you look at the average amount used from the Spraberry down to the Bone Spring 3rd Sand, but there is some indication that the amount of proppant used per interval is changing. When examining the fluid the trend appears a little more clearly, while the overlap in confidence intervals for the mean values is much smaller and there is a noticeable decrease across the formations.
Figure 5a – Total proppant/lateral length
Figure 5b – Total fluid/lateral length
Next, I examined the interaction between proppant and fluid. Figure 6 shows the proppant concentration per gallon. As expected this looks similar to the fluid comparison image, with some separation between the groups. However, there are a few key differences. First the order is almost completely reversed, with the Bone Spring wells having the highest concentration and the Spraberry having the lowest. A final observation on this visualization is that the trend is not completely inversed from the fluid volume trend. This indicates that operators are not adjusting proppant and fluid volumes at the same ratio per geologic interval but rather adjusting them independent of each other.
Figure 6 – Total proppant/total fluid
Examination of Additive Amounts and Treatment Types Across Formations
While other additives typically account for the very small minority of the variance in a completion, I still felt it necessary to do my due diligence and examine their properties. Working under the assumption that a more complex treatment, such as a high-density crosslink, would require more chemicals than a simple slickwater, I summed all additives other than proppant and base water to examine their differences. Because of the relatively small percentages of other additives pumped I needed to log transform the results to more easily compare them. The interesting takeaway here is that there are distinct differences in additive usage between the Wolfcamp and Spraberry intervals to the Bone Spring intervals, indicating that the treatment type does not vary much between formations and is mostly determined by rock type.
Figure 7 – Log transformed additive amount/lateral feet
To draw a conclusion from this data I first have to realize that only looking at the proppant, fluid, and additives will not give me a wholistic view of completions. Treatment rates, pad volumes, and relative concentrations of each material during the hydraulic fracturing of these wells could, and most likely will, vary across each of these formations, even if only in a subtle way.
Keeping the limitations of my research in mind, I looked to interpret the results. Figure 8 gives the averages for each of the key metrics. It can be seen that no two formations have the same average values throughout each metric and there appears to be a distinct trend when considering the larger geologic picture. Shales use more proppant and fluid but in lower concentrations then more traditional reservoir rocks.
Figure 8 – Average completion metrics by formation
The statistician in me would see that there was enough overlap in these averages to be concerned with calling each formation’s completion unique. However, the practical side of me looks at the whole picture (Figure 9) along with the unknown completion parameters and understands that while the differences may be subtle, the summation of subtle differences can be quite large, so it is clear that Permian operators are taking their own advice and each formation is being treated separately.
Figure 9 – Average completion and log metrics by formation
The North West Europe region saw a bumper summer of exploration and appraisal drilling in 2017, with activity back up to a comparable level as prior to the oil price crash at the end of 2014 (see chart below). A combination of oil price recovery to above $50 per barrel and significantly cheaper rig rates — half of 2014 day rates — has prompted operating companies to drill, augmented by the favourable weather conditions during summer.
Figure 1. NW Europe exploration well spuds by quarter
UK takes lead with improving economic conditions
Drill-ready prospects that have been on hold for a couple years, and would likely have been drilled sooner in more favourable economic conditions, finally received approval and moved ahead quickly. A revitalised UK government body under the Oil and Gas Authority (previously under DECC) is arguably another factor. In the UK, a few companies had multiple prospects drilled: Statoil’s drilling campaign saw successful yet uncommercial oil at Mariner Segment 9, their Jock Scott prospect failed to encounter reservoir, and the Verbier updip sidetrack found oil at the second attempt, after an initial unsuccessful well; CNOOC Limited subsidiary Nexen operated two HPHT 150-days plus new field wildcats, with Craster still ongoing, whilst the earlier Glengorm well proved to be a non-starter; Summit Petroleum drilled the Ranger prospect and appraised Avalon; and BP’s Capercaillie prospect was drilled, while the Achmelvich wildcat still ongoing. Other spuds of note include UK onshore Cuadrilla’s shale gas exploration Preston New Road currently ongoing, after a difficult route through the planning procedure, and expected to be hydraulically fracked and flow tested at the end of the year.
Figure 2. Summer 2017 spuds
Norway had the usual spread of drilling in the North, Norwegian and the Barents Seas, which included Barents Sea Wisting and Alta appraisal wells, and Statoil’s multi-billion- barrel Korpfjell prospect 37km from the Norway/Russia border, that which proved to hold less than 0.5 Tcfg. Statoil also drilled Gemini N, Kayak, and Blåmann, proving successful discoveries in the Barents Sea but not resulting in standalone field developments. Ireland saw its first exploration well drilled since 2015, but the highly anticipated Druid/Drombeg well, targeting nearly 5 Bbo, ultimately disappointed operator Providence Resources and partners.
Perhaps the surprise package was notable success in the Netherlands where Oranje-Nassau Energie made a significant gas discovery at Ruby on the Dutch-German offshore border, and Vermillion drilled two onshore gas discoveries, Nieuwehorne-2 and Eesveen-2.
Whether this indicates the end of the decline for exploration and appraisal as a result of the downturn in North West Europe remains uncertain, however planned well numbers suggest a similar number of Q4 wells as the past few years, and that the summer of 2017 was a blip. Norway, UK and Denmark all have firm commitment wells due in the coming years and healthy award numbers in recent bid rounds for exploration acreage. Statoil has a second commitment well on the Korpfjell licence and reports five exploration wells planned for 2018 in the Barents Sea. The summer of 2017 suggests there is an appetite to drill under the right conditions and the summer of 2018 may see a similar quantity of wells being drilled.