Tropical Storm Barry is forecast to become the first hurricane of the 2019 season. The storm is already affecting offshore operation and will soon begin to impact energy infrastructure onshore as well. As projected storm paths appear to be shifting east, Barry is moving away from the heavy energy export infrastructure in the Port Arthur area. However, the storm still poses a threat to energy infrastructure in the Louisiana area. Indeed, Phillips 66 announced that preparing to shut its 253,600 barrel per day Alliance refinery. Other refineries in southern Louisiana may soon follow.
Barry’s cone of uncertainty has it passing by some of the largest oil and gas producing platforms in the Gulf of Mexico. As of 11:30 CDT on Wednesday 07/10/2019, the storm had already led to the evacuation of 15 production platforms with 602,715 barrels of oil per day shut in and 496.2 mmcfd of gas shut-in according to the Bureau of Safety and Environmental Enforcement. Since the EIA leverages BSEE’s outage monitoring as it’s only real-time component in Lower 48 production, that drop will appear in next week’s EIA report.
Although the storm is currently affecting supply, the impact of hurricanes on the US energy picture has drastically shifted over the past several years. US oil production has grown substantially with most of those new barrels are coming from onshore in the Permian Basin of Texas and New Mexico and other shale plays such as North Dakota’s Bakken. In natural gas, a similar situation has occurred and production from the Gulf of Mexico has waned in relative importance. The concern over Gulf of Mexico as a supply hub for production and waterborne imports has fallen. This has been replaced by a demand driven concern about the ability to load tankers for export. Though it appears Barry’s path is going to be favorable, Barry’s could still impact some of the major LNG and oil exporting terminals in the Gulf Coast.
The first terminal likely to be impacted by the storm is the Louisiana Offshore Oil Port (LOOP), which now falls within Barry’s cone of uncertainty. LOOP, the only facility on the Gulf Coast capable of fully loading or unloading a VLCC is still used for imports, but as the chart below illustrates, that is happening far less frequently.
Crude Imports to Morgan City, LA (LOOP)
Source: US Customs & Border Patrol, DrillingInfo
With less of a need to import barrels, LOOP has been more actively loading tankers for export. AIS data shows that the VLCC Aral, capable of holding more than 2 million barrels of crude departed the terminal on July 6th and is now headed for South Korea. However, due to the timing of this storm, it does not appear that planned LOOP crude exports will be impacted. The vessel Atlantic Dawn arrived with a crude cargo from Mexico on July 10. With the need to bring that oil to shore, the terminal would not have been able to move oil out to the terminal anyways.
While LOOP is the only US offshore loading terminal, the Gulf of Mexico plays a key role in the reverse lightering operations that transfer US crude exports from the smaller vessels able to load at US inshore terminals onto the larger vessels that ultimately carry the crude to it’s destination. These activities will likely need to halt given high seas as the storm is expected to travel through many of these designated lightering areas which are shown on the map above in light blue.
As the storm moves towards closer to shore, it’s projected to make landfall in Louisiana between the Mississippi river and Lake Charles. South of Lake Charles lies the new Cameron LNG export terminal. The most recent departure from the terminal was the LNG tanker Gaslog Sydney which departed on July 8th. The Diamond Gas Sakura is in the Gulf of Mexico with a destination of Lake Charles and will likely end up at Cameron. However on July 7th, prior to Barry’s development, the vessel changed the ETA it was signaling from July 18th to August 2nd, so it is unlikely to be impacted by the storm. That delay could be due to reports of challenges with the cooling system at Cameron as it comes online. Upriver of Cameron, Lake Charles is home to 2 refineries, Phillips 66 and Citgo, but like imports through LOOP, both of those refineries now require lower levels of supply via the water than they have in the past. While they aren’t as reliant on waterborne shipments, those refineries could still be impacted by flooding or a loss of power.
Crude Imports to Lake Charles, LA (LOOP)
On the Mississippi river, the storm could impact St. James area oil terminals. The river is already running high due to significant precipitation across the Midwest and this storm will likely exacerbate that situation. Heightened river levels could prevent vessels from being able to safely load or unload cargoes. The St. James area terminals are involved in the growing crude export business, but they have not seen as much growth as have the crude export terminals in Texas. As the table below illustrates, Nustar’s St. James terminal is handling much of the crude export activity taking place in the area.
Likely Crude Export Activity at St. James Crude Terminals (Capacity in Barrels)
Source: VesselTracker, DrillingInfo
Overall given the storms current path, it seems as though it will spare some of the more important pieces of energy infrastructure on the Gulf Coast. The biggest threat to exports from this storm would be if it were to shift further west towards the export hub in Port Arthur. That area features the largest LNG export terminal: Cheniere Sabine Pass, a large LPG and crude export terminal in the Sunoco Logistics Mariner South, as well as other crude export terminals operated by Enterprise Products and Phillips 66. Even if the storm avoids the area, weather could bring the boarding of tankers by harbor pilots to a halt, preventing vessels from being able to arrive or depart. Cheniere has had to shut-in for previous storms and given its activity, a slowdown in its exports, would certainly slow demand and back up supply. As the table below shows, the facility sends out nearly one LNG tanker every day.
LNG Tanker Activity at Cheniere’s Sabine Pass Terminal (Capacity in cubic meters)
Source: VesselTracker, DrillingInfo
For information on some of the capabilities highlighted in this analysis, please contact Bert Gilbert, firstname.lastname@example.org.
US production of crude oil has risen dramatically over the past several years, surpassing that of even Russia and Saudi Arabia, making the US the largest global producer according to the EIA. The surge in production has been driven by fracking — more specifically, the combination of hydraulic fracturing and horizontal drilling — allowing US producers to unlock resources that were not previously accessible. Innovation in the shale patch continues to this day as operators continue to increase the productivity of their wells. The two main levers available to producers are increasing lateral lengths and increasing frac intensity. By pulling these levers, the quantity of oil that each well produces has continually increased.
The chart below is from Drillinginfo’s DPR, DI’s take on the EIA’s Drilling Productivity Report. The purpose of the DPR is to give a short-term (three-month) outlook for oil and gas production from key unconventional plays around the country. The selected chart shows how the production from the average Permian Basin crude well has risen over time. As is clear in the chart, well productivity has continuously grown over the past several years.
But as shale plays have continued to be developed and operators begin to drill within the bounds of their existing wells (infill), an obstacle has appeared. This obstacle, called parent-child interaction, could slow or even reverse the seemingly ever-increasing productivity of shale wells.
The problem of parent-child interaction occurs when operators drill and frac new wells (children) among existing wells (parents). By fracking the well, operators open cracks in the rock through which hydrocarbons are pushed by pressure. But if these new cracks encounter existing cracks, the result can be lower pressures for both the new child and the existing parent, reducing the ultimate recoverable amount of oil. Schlumberger has estimated that these child wells now make up 50% of all wells in the Permian, by far the most productive US shale region.
A recent article from the Wall Street Journal, titled “A Fracking Experiment Fails to Pump as Predicted,” focuses on Encana’s cube project in the Permian Basin. By drilling and completing many wells in a section or drilling unit in a single massive project, Encana sought to reduce costs while reducing the impact of the parent-child interaction. Encana deployed this technology at its RAB Davidson lease in the Permian, pictured below. The finding of the Journal’s article was that Encana was unsuccessful in overcoming the challenges posed by parent-child interaction.
Drillinginfo’s deep database of well-level production data allows users to analyze the performance of the Encana cube wells on their own. The chart below leverages this data to generate production charts for the wells that made up Encana’s cube experiment in the Permian. The chart presents the average well in each of the three cube attempts discussed in the article: RAB Davidson 22 (the first RAB Davidson phase), RAB Davidson 27 (the second) and Abbie Laine 30. The analysis suggests that these wells, completed in 2016 and 2017, initially produced at a higher rate than Encana’s average Midland County vintage 2016 and 2017 wells. After the initial burst of production, the RAB Davidson wells declined at a steeper rate than the average well. Encana’s development at Abbie Laine featured wider spacing and showed a greater initial production rate, closer to that of the average 2018 vintage well. However, it also declined at a steeper rate. So while cube drilling may have lowered Encana’s cost on a per well basis, the data highlights the threat to future lofty Permian production targets if the parent-child problem cannot be solved.
Interested in more analysis of the parent-child issue? Please join Drillinginfo on July 15 at 10:00 AM CDT as we focus on how this issue will impact the Permian Basin and answer questions such as:
- What is the impact of parent-child and infill wells on productivity?
- What does this imply for well-level economics?
- How does this translate to volume forecasts for a midstream system? What is the volume risk?
- How does the lower productivity impact development plans, especially in a world where E&Ps are focused on return to shareholders instead of growth?
To sign up, click here: https://upto.com/e/raUNO.
A string of refinery outages on the US West Coast, also known as PADD 5, have pushed gasoline inventories for this time of year to the lowest level since 2013. As prices have spiked, a surge of gasoline and blending components imports has arrived to satiate the region’s demand. Customs data analyzed by DrillingInfo show that imports of gasoline and blending components to PADD 5 have averaged more than 160,000 barrels per day so far in May, surpassing April’s mark of nearly 145,000.
PADD 5 gasoline and components imports exhibit seasonality. Data from the EIA shows that over the past 10 years, imports increased in the spring, peaked at an average of nearly 50,000 bbls/d for the month of April, declined slightly in May to nearly 48,000, and continued to decline through December. Within the EIA’s data, which goes back to 1981, there are only three months with imports greater than 120,000 bbls/d. This happened in the months of March, April, and May 2007. April 2007 saw the highest level of imports in history, 203,000 bbls/d. March was 167,000, while May was 163,000. April and May 2019 should be joining this club, but due to the nearly two-month lag of monthly data from the EIA, those quantities won’t start to be reported until the end of June.
For a much more real-time perspective on waterborne imports of crude and refined products, DrillingInfo leverages manifests from US Customs and Border Protection. The chart below shows a comparison between DrillingInfo’s customs-based estimate of PADD 5 gasoline and blending components imports and the EIA’s monthly report.
While the EIA does provide a weekly estimate of imports on a PADD level, the customs data allows for a more comprehensive understanding of the details, such as the port of discharge and lading. Looking at the port of discharge, it becomes evident that the biggest driver of the increased imports was addititional volume to Los Angeles. The Port of Los Angeles tends to import gasoline and components during the spring months, and that has been especially true this year. But imports to Los Angeles appear to have peaked in April. May’s record imports are actually more a result of increased imports to Bellingham, Washington.
Turning to the origins of those barrels, the customs data shows that April’s increase in imports was really driven by additional barrels from the Netherlands, along with some from Colombia. The story is different in May, with a big increase in imports from Canada, Belgium, and Ireland. The increase from Canada has not come from the west coast but rather from Point Tupper on Canada’s Atlantic coast. These imports appear to have been done by Musket, the trading arm of Love’s Truck Stops. The manifests show that the company imported two cargoes each from Point Tupper, totaling nearly 290,000 barrels of GTAB (gasoline treated as blendstock) to the West Coast so far in May, with one cargo going to Long Beach and the other to San Francisco.
Point Tupper played a role in backstopping PADD 1 gasoline supplies last summer, delivering an averge of approximately 8,000 bbls/d from May to September. This year, it’s already being called on to deliver product, with over 40,000 bbls/d going to PADD 1 and PADD 3 in April and now more than 30,000 bbls/d to PADD 5 in May. With PADD 5’s refineries coming back online, the surge in imports should begin to subside. The impact of diverting barrels from PADD 1 to PADD 5 remains to be seen, but it could result in additional tightness during the peak demand in the summer.
For a list of vessels that have delivered gasoline and blending components into PADD 5 so far this month, please see the table below.
For questions about accessing US customs import data through DrillingInfo, please contact Bert Gilbert at email@example.com.
Oil price reporting agency Argus recently released a price assessment for a new grade of Permian crude oil. The grade, known as West Texas light (WTL), covers Midland delivered crude with a higher oil gravity (API) between 44.1 and 49.9. At the time of the announcement, Argus reported that WTL was trading at a $1.40 to $2.00 discount to West Texas intermediate (WTI) Midland, a slightly heavier grade. DrillingInfo’s US oil production data shines a light on the origins of this emerging grade of crude.
US oil production has increased rapidly over the past several years as the combination of horizontal drilling and hydraulic fracturing allowed producers to unlock previously inaccessible resources. With these technologies, US exploration and production companies have transformed the Permian Basin in West Texas and eastern New Mexico. Previously considered a past-its-prime backwater, it is now the world’s most prolific source of oil, surpassing even Saudi Arabia’s famed Ghawar field. Production in the Permian increased from less than 1 million barrels per day in December 2010 to over 3.8 million bbls/d by December 2018.
As production in the Permian increased, lighter crude oils, those with a higher API, were mixed with heavier crudes to create a blend with specifications mirroring that of WTI. According to Argus, the supply of these very light crudes has now outstripped the capacity to blend them, forcing pipeline operators such as Enterprise Products and Plains to segregate these barrels and ship them in batches based on classifications shown in the table.
To gain additional insight on the growth of WTL production, we turn to DrillingInfo’s well level production data. Regulators require that in addition to production data itself, oil and gas producers must also report the results of initial tests performed on the oil and gas stream extracted from a well. One element of these initial tests is the API of the crude being produced. This data can be slightly lagged, so the most current months are more likely to be missing and will fill in over time. Despite that limitation, the data provides useful insight into the growth in production of these lighter crudes as well as the variation of API across the Permian Basin. By slicing Permian production according to the specifications laid out in the Enterprise tariff shown above, we can track the growth in light crude oil production from the Permian Basin. In December 2010, the Permian was producing less than 40,000 bbls/d of oil with an API between 44.1 and 49.9, the range specified as WTL. By the end of 2018, WTL production was up to nearly 500,000 bbls/d, with another 150,000 bbls/d of oil and condensate with an even higher API also being produced. Production in the WTI range had grown from roughly 460,000 bbls/d to more than 1.9 million bbls/d. The average API for wells with a reported test oil gravity has also been on the rise, increasing from 37 to nearly 41.5.
The Delaware Basin, one of two sub-basins within the Permian Basin, has been driving the growth in production of these very light barrels. As the chart below indicates, production from the Delaware tends to have a higher API than that of its neighbor to the east, the Midland. While API has increased for both basins since 2010, the Midland Basin has remained in the WTI range, while the average API in the Delaware Basin is now in the WTL range.
While both the Midland and the Delaware have seen tremendous growth since 2010, production from the Delaware has ramped up significantly since 2017, surpassing the pace of the Midland. As this pace has increased, the characteristics of the oil produced in the Delaware are altering the dynamics of the crude markets in the Permian.
The characteristics of the Delaware are evident in the well level data. Among wells with a tested API gravity, more than 30% of production came from those in the range of WTL. Around 50% of production came in the WTI range. In the Midland, production from wells that tested in the WTL range made up only 5%, while nearly 80% of production from wells was in the WTI range.
Drilling activity in the Permian indicates this trend towards higher gravity is likely to continue. According to DrillingInfo’s Rig Analytics, there are more than 260 rigs at work in the Delaware basin relative to the 200 or so rigs working in the Midland. With a greater number of active rigs, growth in the Delaware will continue to outpace that in the Midland. As this trend continues, it will result in even greater supplies of the already discounted West Texas Light crude oil coming to market relative to WTI.