WTI quality issues cause concern

  • Market: Crude oil
  • 28/02/22

Buyers of US WTI still face variable quality issues because of different specifications governing pipelines running from the Permian basin to the Texas Gulf coast.

Most of the main pipelines that carry WTI from the Permian basin in Midland, Texas, to the Gulf coast have standardised gravity and sulphur specifications — 36-44°API and less than 0.45pc — but not every line has specific requirements listed for metals and mercaptans. Metals such as iron can spoil the catalysts that refineries use in their catalytic crackers, while high mercaptans can make it harder to produce lighter products such as jet fuel.

Midstream operators have been trying in recent years to standardise the light sweet WTI stream. But concerns have risen about the quality of Midland-origin WTI cargoes loading in the Houston area over the past eight months. Buyers now say they prefer to receive WTI cargoes at Corpus Christi, Texas, owing to the stricter quality specifications in force on key pipelines linking the Permian basin to the hub. Midstream firms tightened quality parameters following concerns over mercaptans and the high iron content of Corpus Christi WTI cargoes. Some producers have invested in sulphur reduction treatment at the wellhead to reduce the fouling of gathering lines. Chemicals manufacturer Q2 Technologies is among the contractors working with producers and midstream operators to clean up Permian barrels, citing one case where it helped bring more than 50,000 b/d of Permian production to mercaptan levels of less than 75ppm, compared with pre-treatment levels of up to 600ppm.

The relatively new 600,000 b/d Epic pipeline and Phillips 66's 900,000 b/d Gray Oak line have each instituted a 75ppm mercaptan limit on WTI shipments, from April 2020 and November 2020, respectively. Crude shipped along Epic generally loads from the Epic crude marine terminal in Corpus Christi, Buckeye Partners' South Texas Gateway terminal, Flint Hills Resources and the Enbridge Ingleside Energy Center. Gray Oak also delivers to the South Texas Gateway terminal and can deliver 100,000 b/d of crude to the 300,000 b/d Kinder Morgan crude and condensate pipeline to the Houston area.

The tariff regulations for Plains All American's 670,000 b/d Cactus 2 pipeline to Corpus Christi and Ingleside refrain from listing specific mercaptan limits, although Plains adheres to the same 75ppm maximum for WTI and West Texas Light shipments on its crude gathering system in west Texas.

Quality concerns

There are additionally no mercaptan specifications on Magellan Midstream's 275,000 b/d Longhorn and 440,000 b/d BridgeTex pipelines from the Permian basin to the Magellan East Houston (MEH) terminal, which has historically acted as the main trade hub for Midland WTI at the US Gulf coast.

Magellan allowed WTI crude from third-party pipelines to make use of its MEH terminal in October 2020, simultaneously specifying that all deliveries into the WTI pool must have a gravity of 41.0-43.5°API, a sulphur content of less than 0.2pc and maximum 75ppm mercaptan levels. Yet European buyers have said they have received off-specification WTI cargoes from Magellan's Seabrook terminal, which receives crude deliveries from MEH, KMCC and various points in the Houston distribution system.

The new 1.5mn b/d ExxonMobil-led Wink-to-Webster pipeline system, which went into service at the start of 2022, is expected to adhere to the MEH-WTI quality parameters, and may deliver a better-qualityWTI to Enterprise Products' Echo terminal, which connects to most of the Houston-based marine infrastructure along the Houston Ship Channel.


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28/05/24

Norway sees record oil, gas investment in 2024

Norway sees record oil, gas investment in 2024

London, 28 May (Argus) — Norway's oil and gas sector is on course to hit record investment levels this year, boosted by rising costs and a flurry of projects that got off the ground in late 2022, according to the latest forecast from government data provider Statistics Norway. Total investment in oil and gas activity in the country, including pipeline transportation, is now projected to reach 247bn Norwegian kroner ($23.5bn) in 2024, up by 15pc from 2023 and 10pc higher than the previous record set in 2014. This year's investment growth is underpinned by higher spending on field development, thanks to a record number of new project approvals in 2022. "It is common for development projects to have higher investments in the second year of development than in the first," Statistics Norway said. There was a flurry of development plans submitted to Norwegian regulators towards the end of 2022 as operators rushed to beat the end of a temporary tax relief regime that was introduced in 2020 to help the oil and gas sector weather the effects of the Covid-19 pandemic. The investment forecast for next year is around Nkr3bn higher than the previous estimate for 2024 made in February. Higher spending estimates on producing fields and on exploration drove the upwards revision. Statistics Norway has also raised its forecast for oil and gas sector investment in 2025, to Nkr216bn from Nkr205bn. Next year's forecast could be revised higher still as companies confirm future spending plans, although Statistics Norway said it expects only a few new developments to be launched in the next 12 months. By James Keates Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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India offers oil, gas, CBM in special upstream round


28/05/24
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28/05/24

India offers oil, gas, CBM in special upstream round

Mumbai, 28 May (Argus) — India is seeking bids through a special upstream bidding round for two discovered small oil and gas fields located in the Mumbai offshore region and one coal-bed methane (CBM) gas field in West Bengal. The notice inviting the bids will be launched on 28 May with submission of bids to close on 15 July, said India's upstream regulator the Directorate General of Hydrocarbons (DHG). Details about potential reserves were not provided and are likely to be in the follow-up notice. Discovered Small Fields bid rounds were launched in 2016 to boost domestic crude and gas production and reduce the country's dependency on imports. Since then 67 oil and gas fields were offered in the first round in 2016 with in-place locked hydrocarbons reserves of 40mn t of oil (293mn bl) and 22bn m³ of gas. A second round in 2018 saw 59 fields reoffered with around 189mn t of oil and oil equivalent gas. The third round in 2021 offered 75 fields with a total resource potential of around 230mn t of oil equivalent. India has also announced the ninth bidding round for 28 upstream oil and gas blocks in the ninth Open Acreage Licensing Programme. The deadline to submit bids was initially due by 29 February but was then extended to 15 May and again to 15 July . Of the 28 blocks offered, nine are onshore blocks, eight shallow-water blocks and 11 ultra-deepwater blocks across eight sedimentary basins with an area of 136,596.45 km². The DHG "carved out" five of these blocks, while the remaining 23 blocks are based on expressions of interest received from companies during the April 2022-March 2023 fiscal year. India's crude and condensate production was 589,000 b/d in 2023-24 , up by 0.5pc from the previous year, according to oil ministry data. Its dependence on crude imports rose to around 88pc in 2023-24 from 87pc the previous year. By Roshni Devi Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Iran's Raisi’s death raises longer-term uncertainty


24/05/24
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24/05/24

Iran's Raisi’s death raises longer-term uncertainty

The president's demise may not affect Iran's energy role, but heightens uncertainty over the country's long-term leadership, writes Nader Itayim Dubai, 24 May (Argus) — The death of Iran's president, Ebrahim Raisi, in a helicopter crash on 19 May has unleashed a host of questions as to what lies ahead for the Islamic Republic at a time when it is already facing a slew of challenges within its borders and beyond. The nature of Iran's leadership suggests there will be little immediate change, irrespective of who the next president is, but the longer-term impact looks far more uncertain. The political shock is unlikely to augur any change in the oil market role of Opec's third-largest producer. It has steadily raised covert crude exports to China over the last year, despite being under US sanctions — although it could soon face new challenges on that front. Iran continues to supply its Yemeni proxy the Houthis with weapons to disrupt Red Sea shipping, in opposition to Israel's actions in Gaza. And conflict between Israel and Iran recently became open and direct for the first time, but pulled back from the brink without escalating into a conflagration that could catch the key oil producing region of the Mideast Gulf in its crossfire. Against this turbulent backdrop, Raisi lost his life travelling back to Iran from Azerbaijan, along with his foreign minister Hossein Amir-Abdollahian and two other officials. Investigations into the cause of the crash are ongoing, but Iranian officials are roundly pointing to difficult weather conditions. Raisi's demise has thrown Iran's election cycle into disarray. The country was due to hold its next presidential election in the summer of 2025, but the government has now had to schedule one for 28 June. Despite his less-than-stellar performance in his nearly three years in office — Iran's economy is in dire straits, inflation hit 40pc this year and the Iranian rial has slipped by 15pc against the US dollar in the past 12 months — Raisi was still seen as a shoo-in for re-election. This was a reflection of Iran's electoral system, in which most candidates that register to run are disqualified after vetting by the powerful conservative-dominated Guardian Council, leaving only a few that the council and Iran's supreme leader, Ayatollah Ali Khamenei, deem acceptable. Its decision to disqualify all prominent moderate and reformist candidates in the last election in 2021 paved the way for Raisi — an ultra-conservative former chief justice — to win the presidency after losing to the more moderate incumbent Hassan Rohani in 2017. Four funerals and an election With the country in mourning this week, nobody has yet publicly thrown their hat into the ring. But several familiar names are beginning to make the rounds in Iranian media. To date, two stand out. Iran's now caretaker head of state, Mohammad Mokhber, would — despite his limited political career — represent a degree of continuity for the leadership, and is increasingly being mentioned in discussions around the presidency. As is parliament speaker Mohammad Baqer Qalibaf. There is also the possibility that the Guardian Council green lights some popular, more moderate-leaning candidates, such as Rohani's former foreign minister Mohammad Javad Zarif or former parliament speaker Ali Larijani, in an attempt to draw an increasingly disenchanted and apathetic electorate back to the polls. The 2021 election saw a voter turnout of just 49pc, down from 73pc in 2017, while the more recent parliamentary elections in March saw 42pc participation nationwide — and just 7pc in the capital, Tehran — down from 63pc in 2016. But Iran watchers are not holding their breath. "I am not optimistic they will try to open up the field," Washington DC-based Centre for International Policy senior fellow Sina Toossi says. "Yes, there is a legitimacy crisis. But if past elections tell us anything, it is that they feel they don't need that high a turnout, and that they can repress any protest," he says. Whatever the outcome of the ballot, there is little expectation that it will translate into any material change, because the country's power dynamics place the supreme leader, and not the president, as the ultimate decision-maker. "The role of the president has already been marginalised significantly," according to Esfandyar Batmanghelidj, founder and chief executive of Bourse and Bazaar Foundation, a think-tank focused on Iran's economy. "Now, the president dies, and it's surprisingly inconsequential from a policy standpoint because the president wasn't an independent political operator." 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That was at least one factor behind his relatively quick rise. Khamenei's second son, Mojtaba, has been repeatedly suggested as another leading prospect to potentially succeed his father. For many, it appeared a straight contest between the younger Khamenei and Raisi. This would imply that Raisi's death has effectively cleared the path for Mojtaba to succeed his father. But the latter's candidacy, let alone his ascent, remains anything but certain. "For now, Mojtaba does not strike me as a viable candidate," Geneva Graduate Institute senior research associate Farzan Sabet says. "A son succeeding a father smacks too much of monarchy. He has not held senior political, executive or administrative posts, he has very little public profile, and does not seem to have real standing among the Shia clergy." What is more, Mojtaba has for many years held significant sway over the office of the supreme leader, a key focus of economic and political power in Iran's system of governance. "He has carved out a role… [that] has a lot of influence," Batmanghelidj says. "Why would he jeopardise [that]?" Assuming that is the case, the prospective post-Khamenei leadership of the region's most disruptive power faces new uncertainty that may prove far more consequential than its president's death. Chinese imports of Iranian crude Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Q&A: Oman Shell to balance upstream with renewables


24/05/24
News
24/05/24

Q&A: Oman Shell to balance upstream with renewables

Dubai, 24 May (Argus) — Shell has been in Oman for decades now and had a front row seat to its energy evolution from primarily an oil producing nation to now a very gas-rich and gas-leaning hydrocarbons producer. Argus spoke to Oman Shell's country chairman Walid Hadi about the company's energy strategy in the sultanate. Edited highlights follow: How would you characterize Oman's energy sector today, and where do new energies fit into that? Oman is one of the countries where there is quite a bit of overlap between how we see the energy transition and how the country sees it. Oman is clear that hydrocarbons will continue to play a role in its energy system for a long period of time. But it is also looking to decrease the carbon intensity to the most extent which is viable. We need to work on creating new energy systems or new components of energy system like hydrogen and EV charging to facilitate that. It is what we would like to call a 'just transition' because you think about it from macroeconomic perspective of the country and its economic health. Shell is involved across the energy spectrum in Oman – from upstream gas to alternative, clean energies. What is Shell's overall strategy for the country? In Oman, our strategic foundation has three main pillars. The first is around oil and liquids and our ambition is to sustain oil and liquids production. At the same time, we aim to significantly reduce carbon intensity from the oil production coming from PDO. The second strategic pillar is gas, and our ambition here is to grow the amount of gas we are producing in Oman and also to help Oman grow its LNG export capabilities. The more committed we are in unlocking the gas reserves in the country, the more we can support Oman's growth, diversification, and the resilience of its economy through investments and LNG revenue. Gas also offers a very logical and nice link into blue and green hydrogen, whether in sequence or as a stepping stone to scale the hydrogen economy in the country. The last strategic pillar is to establish low-carbon value chains, predominantly centered around hydrogen, more likely blue hydrogen in the short term and very likely material green in the long term, which is subject to regulations and markets developing. How would you view Oman's potential to be a major exporter of green hydrogen? When examining the foundational aspects of green hydrogen manufacturing, such as the quality of solar and wind resources and their onshore complementarity, Oman emerges as a highly competitive country in terms of its capabilities. But where we are in technology and where we are in global markets and on policy frameworks — the demand centers for green hydrogen are maturing but not yet matured. I think there will be a period of discovery for green hydrogen globally, not just for Oman, in the way LNG started 20-30 years ago. When it does, Oman will be well-positioned to play global role in the global hydrogen economy. But the question is, how much time it is going to take us and what kind of multi-collaboration needs to be in place to enable that? The realisation of this potential hinges on several factors: the policies of the Omani government, its bilateral ties with Japan, Korea, and the EU, and the technological advancements within the industry. Shell has also been looking at developing CCUS opportunities in the country. How big a role can CCUS play in the region's energy transition? CCUS is going to be an important tool in decarbonising the global energy system. We have several projects globally that we are pursuing for own scope 1, scope 2 emissions reductions, as well as to enable scope 3 emissions with the customers and partners In Oman, we are pursuing a blue hydrogen project where CCUS is a clear component. This initiative serves as a demonstrative case, helping us gauge the country's potential for CCUS implementation. We are using that as a proof point to understand the potential for CCUS in the country. At this stage, it's too early to gauge the scale of CCUS adoption in Oman or our specific role within it. However, we are among the pioneers in establishing the initial proof point through our Blue Hydrogen initiative. You were able to kick off production in block 10 in just over a year after signing the agreement. How are things progressing there? We have started producing at the plateau levels that we agreed with the government, which is just above 500mn ft³/d. Block 10 gas is sold to the government, through the government-owned Integrated Gas Company (IGC), which so far has been the entity that purchases gas from various operators in Oman like us, Shell. IGC then allocates that gas on a certain policy and value criteria across different sectors. We will require new gas if we are going to expand LNG in Oman. There is active gas exploration happening there in Block 10. We know there is more potential in the block. We still don't know at what scale it can be produce gas or the reservoir's characteristics. But blocks 10 and 11 are a combination of undiscovered and discovered resources. We are aiming to significantly increase gas production through a substantial boost. However, the exact scale and timing of this expansion will only be discernible upon the conclusion of our two-year exploration campaign in the block. We expect to understand the full growth potential by around mid to late 2025. Do you have any updates on block 11? Has exploration work there begun? We did have a material gas discovery which is being appraised this year, but it is a bit too early to draw conclusions at this stage. So, after the appraisal campaign is completed, we will be able to talk more confidently about the production potential. Exploration is a very uncertain business. You must go after a lot of things and only a few will end up working. We have a very aggressive exploration campaign at the moment. We also expect by the end of 2025, we would be in a much better position to determine the next wave of growth and where it is going to come from. Shell is set to become the largest off taker from Oman LNG, how do you view the LNG markets this year and next? 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We have been historically and predominantly focused on east and we continue to see east as core LNG market with focus on Japan, Korea, and China. Europe has also emerged on the back of the Ukraine-Russia crisis as growing demand center for LNG. Over time we might focus on different markets to a certain extent. It will be driven on maximising value for the country. By Rithika Krishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Opec+ to take June meetings online


24/05/24
News
24/05/24

Opec+ to take June meetings online

Dubai, 24 May (Argus) — Meetings to discuss Opec+ crude output policy that had been scheduled to take place in Vienna at the start of June have been pushed back by a day and will now be held online. The meetings — one involving Opec ministers, another involving the wider Opec+ coalition and a third consisting of the group's Joint Ministerial Monitoring Committee (JMMC) — will "convene via videoconference on Sunday 2 June 2024", the Opec secretariat said on Friday. The original schedule was for Opec+ ministers to meet in person on 1 June. The announcement puts to bed more than a week of rumours and delegate chatter about whether or not the meeting would take place in person as speculation mounts around what policy decision the group would need, or be prepared, to take. Effectively, the only thing up for debate at these meetings is the fate of the 2.2mn b/d supply cut that eight member countries, led by Saudi Arabia and Russia, committed to after the Opec+ group's last meeting in late November. That cut was originally due to last for just three months, but it was later extended for another three months until the end of June. Several weeks ago, when oil prices were under sustained upward pressure in the face of tightening fundamentals and rising geopolitical tensions, expectations were high that the group would agree to begin unwinding at least part of the 2.2mn b/d from July. But a relative easing of tensions in the Middle East, coupled with signs of continued restrictive monetary policy by the US Federal Reserve and other major central banks, has since led to a softening of oil prices and with that a change in sentiment among Opec+ delegates about what the group should do next. Delegates today argue that the market is on the whole well-supplied and in no need of additional supply from the group, particularly given the uncertainty around the outlook for oil demand, highlighted by the wide range of growth projections for 2024. At one end of the spectrum, Opec sees oil demand growth of 2.25mn b/d this year. At the other end, the IEA recently revised down its 2024 growth forecast for a second consecutive month. It now stands at 1.06mn b/d. Two Opec+ delegates said earlier this week that they expect the eight countries to extend the 2.2mn b/d cut in its entirety beyond the second quarter. One said they could extend it through to the end of the year. Compensation plans A renewed emphasis by Opec+ in recent weeks on the need for those member countries producing above their targets to not only scale back but also compensate fully for their past overproduction could be interpreted as acknowledgement by the group that the market is indeed well-supplied. Iraq and Kazakhstan, the group's biggest overproducers this year, this month issued detailed programmes outlining how they plan to compensate , while Russia this week acknowledged it had exceeded its Opec+ target for April and said it would soon submit a plan to the Opec secretariat detailing how it will make up it. Although all eyes will be on the fate of the 2.2mn b/d cut at the upcoming meetings, the fact it is a voluntary pledge and one agreed by only a handful of countries means, in theory, a decision need not happen at the ministerial meeting. As the eight countries participating in that cut are all members of the JMMC, there is a good chance the decision gets announced at the committee's meeting instead. By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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