The world’s largest emergency stockpile of crude oil is quickly falling apart.
The stockpile’s infrastructure, which currently stores 695.1 million barrels at four sites along the US Gulf Coast, is nearing the end of its design life and in need of a roughly $2 billion makeover, US Department of Energy officials claim.
“We’ve had several significant equipment failures over the last couple years that have affected our operational capability,” said Bob Corbin, the DOE deputy assistant secretary who oversees the stockpile, formally known as the US Strategic Petroleum Reserve.
In April, a water pipe at the DOE’s Big Hill site in Winnie, Texas failed, less than a year after a crude oil storage tank failed at the Bryan Mound SPR site near Freeport, Texas.
Throughout the system, pipes are corroding, tank floors need to be replaced, wells are failing mechanical integrity tests and pump motors, after decades of dealing with harsh weather and salty air off the Gulf of Mexico, are breaking down beyond repair, DOE officials claim.
Corbin said these issues complicate the ability of DOE to both drawdown and distribute crude oil at times of severe supply distributions, which is the primary reason the SPR was created more than four decades ago. They also complicate US’ ability to meet obligations under international agreements and could endanger energy security.
Last week, Corbin led a media tour of the Bryan Mound SPR site, the largest of the four SPR sites in Texas and Louisiana.
Bryan Mound is a 500-acre site which currently holds 245 million barrels of crude (2.1 million barrels below its design storage capacity) in 19 operational storage caverns.
The SPR has two types of caverns in salt domes: SPR-designed caverns and Early Storage Reserve-caverns. The ESR caverns are typically repurposed salt domes and have operational restrictions the more current SPR-designed caverns do not have. The ESR caverns at the Bryan Mound site were originally used by Dow Chemical to store magnesium. The entire SPR has 49 SPR-designed caverns and 11 ESR caverns.
Cavern 5 at Bryan Mound is the largest crude oil storage cavern in the world and can store up to 37 million barrels of crude. DOE claims that underground caverns, which are roughly 2,000 to 2,200 feet in depth and 200 feet in diameter, can be built for about 1/5 of the cost of conventional surface tanks and have operating costs of less than 30 cents/barrel. The SPR primarily holds light crude, but has 75 million barrels of medium sour, roughly 10.8% of its total inventory. It currently hold 266.1 million barrels of light sweet crude, 38.3% of its inventory, and 354 million barrels of light sour, or 50.9%.
Bryan Mound currently holds 68.6 million barrels of sweet crude in six caverns and 176.4 million barrels of sour crude in 13 other caverns. The site has 45 operational wells and connects to four crude oil distribution sales points: Freeport terminal ship docks; Jones Creek pipeline; Texas City terminal ship docks; and Texas City terminal pipeline.
Congress has approved sales of millions of barrels of SPR crude to help pay for unrelated transportation plans and a modernization effort for the SPR. These sales, which will continue through fiscal 2025, could take the SPR from its current inventory of 695.1 million barrels to 530 million barrels, a threshold DOE needs to stay above in order for the President to maintain statutory authority to approve emergency releases from the stockpile.
“If you get below 530 million barrels…that would basically take away the authority of the president to conduct limited drawdowns, which means small disruptions, not even huge disruptions, would be difficult, if not impossible to respond to as a result,” Corbin said.
Corbin said while millions of barrels of SPR crude will be sold off over the next nine years, he’s not sure if that crude will ever be replaced.
“Buying and selling oil at the same time, from a net inventory result, I think is counterproductive, but you just don’t know what’s going to happen,” he said.
In a report Corbin authored, DOE is expected to recommend an ideal size for the SPR, in light of the ongoing growth of US shale oil. Corbin declined to comment on that recommendation, but said the SPR will be “smaller than it is today” but its exact size is yet to be determined. The report is expected to be released within a month.
The SPR’s drawdown rate, the pace at which crude can be pushed out of storage caverns to pipelines, is designed to be 4.415 million b/d over 90 days before the rate begins to fall. But a smaller SPR could reduce that rate dramatically, hindering the ability of DOE to bring crude to a distressed global market.
“As you reduce your inventory levels, and reduce the number of caverns that oil is stored in, because of flow hydraulics, it changes both the drawdown rate and the maximum duration that you can sustain that rate,” Corbin said.
At the same time, the SPR is also losing as much as 2.4 million barrels per year by both natural creep, caused by the force of the earth pushing on the caverns, and induced creep, which occurs when a cavern needs to be depressurized for maintenance, he said.
“The creep issues will continue going forward, there is nothing anybody can do about those,” Corbin said. “The question becomes, from a planning perspective how does creep impact your storage capacity going forward and how does it impact your requirements for storage capacity going forward?”
Each SPR site uses a system where water is injected into caverns, displacing stored oil and brine and pushing it into crude pipes and eventually sent into pipelines and ships to the Gulf of Mexico.
The ability of that system to work, however, has been complicated both by the SPR’s aging infrastructure and changes to how crude oil now moves in the US. DOE is pushing for dedicated marine terminals in order to ship out crude at times of supply shocks so that crude which would otherwise be sent out from existing marine facilities would not be displaced. Details of this request will be featured in DOE’s upcoming report, Corbin said.
The SPR was established through the Energy Policy & Conservation Act of 1975 and is beginning to show its age. The floor of this tank (pictured above) has corroded and needs to be replaced.
During the tour, a crew worked on repairing a well of one cavern which had failed a state-mandated mechanical integrity test.
The Bipartisan Budget Act of 2015 calls for sales between fiscal 2017 through 2020 totaling $2 billion from the SPR to pay for the effort to address many of these issues. But Congress still needs to appropriate the funding for this effort.
DOE warns that if sales do not take place over the next four fiscal years additional, larger volumes will need to be sold in later years when other sales are already scheduled to take place.
By Brian Scheid, Senior editor, oil news
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According to the Nigeria National Petroleum Corporation (NNPC), Nigeria has the world’s 9th largest natural gas reserves (192 TCF of gas reserves). As at 2018, Nigeria exported over 1tcf of gas as Liquefied Natural Gas (LNG) to several countries. However domestically, we produce less than 4,000MW of power for over 180million people.
Think about this – imagine every Nigerian holding a 20W light bulb, that’s how much power we generate in Nigeria. In comparison, South Africa generates 42,000MW of power for a population of 57 million. We have the capacity to produce over 2 million Metric Tonnes of fertilizer (primarily urea) per year but we still import fertilizer. The Federal Government’s initiative to rejuvenate the agriculture sector is definitely the right thing to do for our economy, but fertilizer must be readily available to support the industry. Why do we import fertilizer when we have so much gas?
I could go on and on with these statistics, but you can see where I’m going with this so I won’t belabor the point. I will leave you with this mental image: imagine a man that lives with his family on the banks of a river that has fresh, clean water. Rather than collect and use this water directly from the river, he treks over 20km each day to buy bottled water from a company that collects the same water, bottles it and sells to him at a profit. This is the tragedy on Nigeria and it should make us all very sad.
Several indigenous companies like Nestoil were born and grown by the opportunities created by the local and international oil majors – NNPC and its subsidiaries – NGC, NAPIMS, Shell, Mobil, Agip, NDPHC. Nestoil’s main focus is the Engineering Procurement Construction and Commissioning of oil and gas pipelines and flowstations, essentially, infrastructure that supports upstream companies to produce and transport oil and natural gas, as well as and downstream companies to store and move their product. In our 28 years of doing business, we have built over 300km of pipelines of various sizes through the harshest terrain, ranging from dry land to seasonal swamp, to pure swamps, as well as some of the toughest and most volatile and hostile communities in Nigeria. I would be remiss if I do not use this opportunity to say a big thank you to those companies that gave us the opportunity to serve you. The over 2,000 direct staff and over 50,000 indirect staff we employ thank you. We are very grateful for the past opportunities given to us, and look forward to future opportunities that we can get.
Headline crude prices for the week beginning 15 July 2019 – Brent: US$66/b; WTI: US$59/b
Headlines of the week
Unplanned crude oil production outages for the Organization of the Petroleum Exporting Countries (OPEC) averaged 2.5 million barrels per day (b/d) in the first half of 2019, the highest six-month average since the end of 2015. EIA estimates that in June, Iran alone accounted for more than 60% (1.7 million b/d) of all OPEC unplanned outages.
EIA differentiates among declines in production resulting from unplanned production outages, permanent losses of production capacity, and voluntary production cutbacks for OPEC members. Only the first of those categories is included in the historical unplanned production outage estimates that EIA publishes in its monthly Short-Term Energy Outlook (STEO).
Unplanned production outages include, but are not limited to, sanctions, armed conflicts, political disputes, labor actions, natural disasters, and unplanned maintenance. Unplanned outages can be short-lived or last for a number of years, but as long as the production capacity is not lost, EIA tracks these disruptions as outages rather than lost capacity.
Loss of production capacity includes natural capacity declines and declines resulting from irreparable damage that are unlikely to return within one year. This lost capacity cannot contribute to global supply without significant investment and lead time.
Voluntary cutbacks are associated with OPEC production agreements and only apply to OPEC members. Voluntary cutbacks count toward the country’s spare capacity but are not counted as unplanned production outages.
EIA defines spare crude oil production capacity—which only applies to OPEC members adhering to OPEC production agreements—as potential oil production that could be brought online within 30 days and sustained for at least 90 days, consistent with sound business practices. EIA does not include unplanned crude oil production outages in its assessment of spare production capacity.
As an example, EIA considers Iranian production declines that result from U.S. sanctions to be unplanned production outages, making Iran a significant contributor to the total OPEC unplanned crude oil production outages. During the fourth quarter of 2015, before the Joint Comprehensive Plan of Action became effective in January 2016, EIA estimated that an average 800,000 b/d of Iranian production was disrupted. In the first quarter of 2019, the first full quarter since U.S. sanctions on Iran were re-imposed in November 2018, Iranian disruptions averaged 1.2 million b/d.
Another long-term contributor to EIA’s estimate of OPEC unplanned crude oil production outages is the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. Production halted there in 2014 because of a political dispute between the two countries. EIA attributes half of the PNZ’s estimated 500,000 b/d production capacity to each country.
In the July 2019 STEO, EIA only considered about 100,000 b/d of Venezuela’s 130,000 b/d production decline from January to February as an unplanned crude oil production outage. After a series of ongoing nationwide power outages in Venezuela that began on March 7 and cut electricity to the country's oil-producing areas, EIA estimates that PdVSA, Venezuela’s national oil company, could not restart the disrupted production because of deteriorating infrastructure, and the previously disrupted 100,000 b/d became lost capacity.