65 Oil/Gas Fields Discovered in 45 Years

Oil/Gas Output Hits Record in 5 Months

Iran sits atop the world’s largest oil and gas reserves combined, amounting to 1,200 billion barrels of oil equivalent (boe). Iran’s petroleum industry is over a century old, but its four-decade achievements have proven outstanding. Iran’s recoverable liquid hydrocarbon reserves amounted to 88 billion barrels before the 1979 Islamic Revolution, which has increased to 340 billion boe thanks to cutting-edge technology.

Iran has proven its achievements in the crude oil, gas, petrochemical, refining, and distribution sectors. Some breakthroughs include the operation of the massive South Pars gas field, the giant Yadavaran oil field, and the Bandar Abbas Gas Condensate Refinery.

Furthermore, 65 oil and gas fields have been discovered, bringing recoverable oil and condensate reserves to 160 billion barrels and recoverable natural gas reserves to 33 tcm. Eight-fold gas production is also an achievement in the E&P sector in the aftermath of the Islamic Revolution.

65 Fields Discovered

Since the 1979 revolution, 65 oil and gas fields have been discovered. South Pars is one of the largest gas reserves in the world. The massive Azadegan and Yadavaran oil fields are among the key exploration achievements following the Islamic Revolution. The rate of success in exploration in Iran has reached 100%.

It has also to be noted that Iran’s petroleum industry was in the hands of foreign countries and companies. Iran was dependent on other countries not only for technology but also for specialists and manpower. In the aftermath of the revolution, foreign manpower gradually left Iran to give way to local specialized labor.

On the other hand, due to restrictions caused by unilateral US sanctions, Iranian companies and contractors found a good chance to go ahead with the domestic manufacturing of equipment. Now local manufacturers and contractors can easily handle megaprojects in collaboration with domestic banks. That is before the Islamic Revolution, foreign companies used to import all equipment either from their respective country or a third country.

Joint Fields Development

Until 1979, Iran’s operation in joint oil fields was limited to the Forouzan oil field which Iran shares with Saudi Arabia, offshore fields jointly owned by the United Arab Emirates (UAE), and the Naftshahr field which Iran shares with Iraq. But today Iran has been developing the West Karoun cluster of fields, South Pars, Balal, and Azar among others.

Iran owns at least 28 joint fields, including 18 oil fields, 4 gas fields, and 6 oil/gas fields. Iran is among a few nations in the world with such a number of joint fields. Of the 28 fields, Iran shares 12 with Iraq, 7 with the UAE, 2 with Qatar, 2 with Oman, 1 with Kuwait, and 1 with Turkmenistan. 

These fields range from small ones to massive ones like the South Pars and West Karoun fields. Iran has tried its best to avoid any halt in the development of these fields despite financial shortages and lack of access to foreign investment due to sanctions.

Iran is estimated to hold 67 billion barrels of oil in place in West Karoun. Iran was recovering nearly 50,000 b/d of oil from these fields, shared with Iraq, until 2013. But it has now reached 480,000 b/d. Furthermore, Nasrollah Zarei, CEO of Petroleum Engineering and Development Company (PEDEC), said recently that the operation of South Azadegan’s central treatment and export plant (CTEP), West Karoun’s output would reach 820,000 b/d.

South Pars, a Megaproject

The development of the South Pars gas field remains the most important project in the history of the Iranian petroleum industry. It is estimated to hold 39 tcm of gas and 56 billion barrels of condensate. Iran’s share amounts to 14 tcm of gas and 18 billion barrels of condensate, making up 8% of the world’s total.

Iran has invested $150 billion in South Pars to recover 2,300 bcm of gas from the giant field, taking in $414 billion in revenue.

Iran is recovering more than 700 mcm/d of rich gas from South Pars, whose thermal value is more than 4 mb/d of oil. In the meantime, the recovery of 650,000-700,000 b/d of gas condensate would highlight the vital status of this massive field in Iran’s energy basket.

Production at South Pars is not limited to gas supply. Part of South Pars products is used to feed petrochemical plants. With this feedstock supply capacity, 21 petrochemical plants operate at South Pars with an output of 39 million tonnes (mt).

Assaluyeh supplies 20.6 mt/y of products at its 13 upstream units, 7.6 mt/y from its 14 midstream units, and 4 mt from its downstream units. It is recognized as Iran’s most powerful petrochemical zone.

Pars Special Economic Energy Zone (PSEEZ) accounts for 90 mt of petrochemicals, of which 45 mt is destined for export. Of 24 petrochemical plants in Assaluyeh, 6 are fed on natural gas. Condensate production, depending on daily gas output, varies between 650,000 and 700,000 b/d. It is mainly fed into the Bandar Abbas Gas Condensate Refinery, which supplies 40% of the national gasoline output. Therefore, it could be argued that 40% of Iran’s gasoline production comes from the Persian Gulf Star Refinery.

The development of the South Pars Oil Layer (SPOL) is another achievement of Iran’s petroleum industry. Its first phase development would build capacity for 35,000 b/d of crude oil, not to mention the annual $510 million revenue.

2.4mb/d Refining Capacity

The refining capacity of Iranian refiners stood at 1.2 mb/d during the early days following the Islamic Revolution. Four decades on, 9 refineries are operating at 2.4 mb/d.

The Abadan oil refinery was recommissioned with a 130,000 b/d capacity in 1989 following the end of the imposed war. It produces LPG, gasoline, kerosene, gasoil, jet fuel, fuel oil, base motor oil, bitumen, oil solvents, sulfur, naphtha and associated gas.

Following the construction of the Abadan oil refinery i.e. the first in Iran, more refineries were planned and built. The Kermanshah, Lavan, Tehran, Isfahan, Tabriz, Shiraz, Arak, and Bandar Abbas (one oil and one condensate) refineries are among them. They have their development plans to enhance capacity and quality.

Star Refinery

Construction of the Persian Gulf Star Refinery is a big achievement in the post-revolutionary era. This facility was built to make Iran self-sufficient in Euro-5 gasoline production.

It is the most sophisticated treatment facility in the Middle East. It was designed to help perpetuate gas recovery from South Pars, reduce environmental pollution, and guarantee national self-sufficiency in supplying strategic energy commodities like gasoline and gasoil. The facility also supplies LPG, hydrogen, sulfur, jet fuel, and a variety of solvents.

14th Administration

Five months into office, the 14th administration has fared well in terms of oil production and export as well as gasoline and gasoil production among other products.

During this short period, the Ministry of Petroleum has added 60,000 b/d to national crude oil production capacity and 30 mcm/d to natural gas production capacity. On four occasions, the gas production record has been smashed with an output of 1.104 bcm/d.

In its latest report, the Central Bank of Iran (CBI) has introduced a new edition of economic indicators. It has updated some economic data. It shows that Iran’s oil exports increased during the first quarter of the current calendar year compared with the year before. The report put Iran’s oil exports at $17.634 billion during the first quarter. It included crude oil, petroleum products, natural gas, gas liquids, and gas condensate, exported by the National Iranian Oil Company (NIOC), National Iranian Gas Company (NIGC), National Iranian Oil Refining and Distribution Company (NIORDC), and National Petrochemical Company (NPC) among others. That covers customs and non-customs exports.

Gasoline Output Up

With increased feedstock supply to crude oil refineries, gasoline production has grown 10 ml/d, and gasoline output has risen 11 ml/d. When the petroleum products supply increases, foreign currency is saved rather than being spent on imports.

Motor gasoline production averaged 97.5 ml/d during the first five months of the current calendar year. The figure reached 107 ml/d by the end of the third quarter. The CEO of NIORDC has said that gasoline production will likely reach 130 ml/d by the end of the 14th administration’s term in office.

According to the latest data from the Ministry of Petroleum, gasoil production averaged 117 ml/d under the 14th administration, up 6 ml/d year-on-year.

The 5% increase in gasoil production under the 14th administration comes while this liquid fuel has been supplied 11% above planned.

Official data also show that gasoil supply to power plants under the 14th administration reached 4 billion liters, up 45% year-on-year.

Jacket Loaded for Belal Field Platform

The jacket for the platform of the development of the Belal gas field was recently loaded on Jetty No. 3 of Iran Marine Industrial Company (SADRA) in Bushehr to be finally installed on the reservoir block of this project at the Iran-Qatar border in the Persian Gulf. The jacket and its belongings weigh 1.800 tonnes with its piles weighing 1,256 tonnes. It was built with a $16 million investment. If weather conditions remain favorable, the jacket will have been installed on its site before the end of the current calendar year in March 2025.

The Belal gas field lies about 40 km east of the South Pars gas field. It was discovered in 2003 by the National Iranian Oil Company (NIOC) Directorate of Exploration.

The agreement for the development of the Belal gas field was signed in September 2019 between Pars Oil and Gas Company (POGC) and Petropars. Construction of the wellhead jacket of the Belal gas field began in late May 2024, recording 1.3 million persons-hours of accident-free work.

Jacket 65m below the Seabed

Ehsan Mohammadi, manager of the Belal gas field development project, said in light of the national priority for developing joint oil and gas fields, this project is prioritized by POGC due to the necessity of boosting gas production capacity and overcoming energy imbalance in the country.

Construction and loading of the wellhead jacket is key to drilling wells and installing offshore installations for the Belal development. He said the jacket is destined to be installed 65 meters below the Persian Gulf bed.

The Belal gas field is to be developed in five packages. In addition to building and installing a wellhead jacket, drilling appraisal wells was done by Dana Drilling Co. in early 2023. Currently, building the top drive is underway by Iranian Offshore Engineering and Construction Company (IOEC) while Petropars Oilfield Services Co. (POSCO) is in charge of drilling development wells. Building an offshore pipeline and fiberoptics will be awarded in the near future.

Once developed, the Belal gas field would produce 14.2 mcm/d of gas and 10,000 b/d of condensate.

Belal Complexity

Mohammadi said Belal’s gas would be delivered by a 30-km pipeline to Platform 12A of South Pars before being sent to the refinery of SP12 via a subsea line.

Commenting on the differences between offshore and onshore gas field development, he said: “Development of offshore gas fields requires more sophisticated technology and equipment due to sour gas and high humidity. As the Belal field’s gas is sour, the field becomes more complicated to develop.”

Touching on the development of this sophisticated field by Iranian contractors, he said: “Earlier, an appraisal/exploration well was drilled by local experts on the site of the gas block.”

Mohammadi said that POGC had fully mastered the technology for offshore development, adding: “When we decided to install the jacket on the appraisal well drilled below the seabed, we knew that it was risky, but it would save us 300 days. Therefore, relying on the skills and expertise of local manpower, we were sure we would do it.”

“The Belal field has an oil and a gas section. The gas section has been assigned to POGC with Petropars handling the job as a general contractor,” he said.

Farshid Shahryari, director of the Belal project at Petropars, said seven more wells would be drilled in the field.

“After the jacket has been installed, the drilling rig would be moved there and in parallel, we would be building and installing the top drive, for which an agreement has been signed,” he said.

The Belal gas field lies 90 km southwest of Lavan Island and about 70 meters deep underwater. Shared by Iran and Qatar, it is estimated to hold 3 tcf of gas and more than 100 million barrels of condensate in place.

West Karoun Output Capacity to Hit 820,000 b/d

Iran’s West Karoun cluster of fields is estimated to hold more than 67 billion barrels of oil in place. Until 2013, Iran recovered 50,000 b/d from these fields jointly owned with Iraq. But currently, Iran is extracting 480,000 b/d from the same fields. Nasrollah Zarei, CEO of Petroleum Engineering and Development Company (PEDEC), tells “Iran Petroleum” that West Karoun would be supplying 820,000 b/d once the Central Treatment and Export Plant (CTEP) of the South Azadegan field becomes operational next year. Established in 2000, PEDEC has so far developed the onshore Soroush/Norouz, Phases 1 and 2 of Darquain, Belal, North Azadegan, and Yadavaran fields as well as the offshore Salman and Forouzan fields.

The following is the full text of the interview Nasrollah Zarei gave to “Iran Petroleum”.

How much does South Azadegan produce now?

Currently, the field is producing 144,000 b/d, which would increase by 30,000 b/d as 26 new wells are coming online there. Furthermore, by resorting to 20 wells through acidizing operations, another 20,000 b/d would be added to South Azadegan’s output. To lift output in 2025, we intend to repair downhole pumps for 50 wells, which would lead to a 30% increase in the wells’ production. Finally, the Azadegan field would see its output reach 200,000 b/d after the first development phase.

A contract for the integrated development of the Azadegan field was signed by a consortium of E&P companies and banks last March. Which stage is it in now?

The Azadegan field holds 28 billion barrels of oil in place. The first phase of North Azadegan became operational in 2015. South Azadegan is also being developed by PEDEC. As Iran and Iraq jointly own Azadegan, its development is very important to Iran. That is why the National Iranian Oil Company (NIOC) signed an agreement with Dashte Azadegan Arvand Oil and Gas Development Company (DAOGC) for the integrated development of Azadegan. Under the agreement, the field would be developed over eight years. Production from this field is projected to reach 600,000 b/d after the second phase of development, up from 400,000 b/d. As this field holds significant oil reserves in place, we may need to consider third-phase development.

The first phase of South Azadegan’s CTEP was planned to come online by next March. Where is it now?

The current production capacity at West Karoun is 480,000 b/d. CTEP, which is the largest oil processing facility in Iran, would help raise West Karoun’s production to 820,000 b/d. Therefore, CTEP is very important for PEDEC. We are trying to bring the first train of CTEP online by March 2025 The second train is planned for April 2025 while the last two trains will become operational during 2Q of 2025.

The first phase of the Yadavaran oil field came online in November 2016. Do you plan to enhance its output?

Under a buyback deal signed with a Chinese company for the development of the Yadavaran oil field, it was expected to be developed in three phases. As you know the first phase became operational in 2016. However, the second and third development phases were delayed due to sanctions. After completion of legal work, this field was assigned to three local contractors. Currently, three drilling rigs are operating at Yadavaran. The number of rigs is expected to rise. Yadavaran’s current output is 114,000 b/d, which is forecast to grow to 156,000 b/d in 1 and a half years.

How much are Sepehr and Jofair producing now?

The development of Sepehr and Jofair fields was a successful IPC-style contract. It was fully commissioned by Pasargad Energy Development Company, an Iranian firm. Production from these fields has recently increased to 51,000 b/d, which is expected to reach 62,000 b/d by March 2025. That would mean the obligation for a 22,000 b/d output hike in this project has been fulfilled.

In which phases are Cheshmeh Khosh, Dalpari, East Paydar, Aban, and West Paydar developed?

These IPC projects are under development. Our current production from Cheshmeh Khosh, Dalpari, and East Paydar stands at 75,000 b/d, which is expected to reach 110,000 b/d next calendar year. Production from Aban and West Paydar is also planned to increase by 10,000 b/d by 21 March 2025. In these projects, we have tried to use cutting-edge technologies. The first two-directional well is being drilled in the Aban field while reinforced thermoplastic pipe (RTP) technology is used in West Karoun projects. Furthermore, at Cheshmeh Khosh and Dalpari, a solar power plant would be launched.

PEDEC has signed agreements with universities and science-based companies for some equipment. How successful has it been so far in this regard?

PEDEC is currently operating three major projects in collaboration with groups operating for the first time in this sector. For instance, the production of the first fluid to replace bromide calcium for well completion was sponsored by PEDEC. After successful tests, under the instructions of the CEO of NIOC, science-based companies received significant support. In West Karoun fields, particularly in the Hoveyzeh Marshes, RTP technology is to be used. For this purpose, two major agreements were signed with the manufacturers of such pipes in the cities of Shiraz and Yazd to facilitate domestic sourcing of this equipment. An agreement is also signed with the Amir Kabir University of Technology to establish a specialized lab in the Faculty of Petroleum Engineering. Such cooperation would include R&D in fractured layers, and acidizing operations in inactive wells for enhanced production at the Sepehr and Jofair projects. This research is underway at a lab scale at the Amir Kabir University of Technology. If successful, it will come online next Iranian calendar year.

$17bn Investment in SP Compression Projects

The South Pars gas field, jointly owned by Iran and Qatar, holds 8% of global gas reserves and about half of Iran’s gas deposits. The development of South Pars, known to be the world’s largest, is highly significant. Iran’s Minister of Petroleum Mohsen Paknejad said recently that $6 billion agreements would be signed for gas compression at South Pars. He said a total of $17 billion would be needed for pressure boosting at South Pars, which would earn the country $800 billion by increasing gas and condensate output at the offshore massive reservoir.

Discovered in 1990 by the National Iranian Oil Company (NIOC), South Pars lies 3,000 meters below the seabed. Iran holds 3,700 sq km and Qatar owns 9,700 sq km of South Pars in the Persian Gulf. South Pars is estimated to hold about 14 tcm of recoverable gas and 18 billion barrels of condensate.

Why South Pars Matters to Iran

South Pars is a vital artery for Iran, as it remains the largest source of natural gas for the country. It supplies the bulk of domestic gas needs. In addition to meeting domestic demand, South Pars provides gas for export to Iraq and Turkey, which yields hard currency revenue for the country. South Pars meets 70% of Iran’s gas needs. The natural gas recovered from South Pars is used as feed for petrochemical plants and to generate electricity.Therefore, as far as energy security is concerned, this field is economically and strategically important for Iran. Sepahdar Abbaszadeh, a deputy CEO of Pars Oil and Gas Company (POGC), recently said South Pars hit a production record of 714 mcm/d.

Gas Compression is a Must

Gas recovery from South Pars is experiencing fall-off on an annual basis and therefore production at its blocks should be preserved. According to experts, pressure fall-off at South Pars is to enter a new phase in 2026. Paknejad has already prioritized compression projects as a priority of the Ministry of Petroleum. In case this project is not implemented, South Pars would be losing 25 mcm a year. The 14th administration is considering seven compression centers in a bid to resolve the challenge of pressure fall-off at South Pars, which would require $2.5 billion in investment. Paknejad has said that a $6 billion package of compression projects would have been signed by March 2025. He has said that about $17 billion in investment would be needed for compression projects, which would earn the country $800 billion as far as South Pars would be producing gas and condensate. Why should compression platforms be installed at South Pars? The pressure from existing wells in South Pars platforms should be normally 120 Bar to carry 1bcf of gas onshore. Therefore, when this pressure drops to 100 Bar, it would not be easy to carry 1bcf of gas and when it comes down to 90 Bar, only 700 mcf of gas may be carried onshore, which would finally cause pressure fall-off. In other words, wellhead pressure would drop gradually, resulting in an output fall. That highlights the role of compression platforms. Pressure fall-off in gas production would result in a lower gasoline supply. Therefore, with pressure fall-off, gas condensate production drops as well. If this challenge is not overcome, exorbitant costs would need to be spent on electricity, gas, and gasoline imports.

Technologies Needed for Compression

Compression platforms with a capacity of 2 bcf are able to enhance pressure to 90 Bar. Iran aims to build compression platforms at its onshore yards, but as such platforms would weigh 20,000 tonnes each, there is no experience of more than 7,000-tonne platforms in Iran, first and foremost necessary infrastructure should be provided.

South Pars has 38 platforms including production and logistic platforms. They are similar to each other. Priority is given to border platforms to prevent gas migration.

Some of the characteristics of this pressure-boostingplatform are: sophisticated design, the need for proper equipment layout, and compliance with safety and operational issues.Its installation requires the application of the float-over method. The conceptual and basic design of the gas pressure boosting platform in South Pars was prepared by an international consultant to serve as an accurate model for Iranin South Pars phases.

Pressure boosting is the most important and strategic project of the Ministry of Petroleum due to its role in gas and condensate production, gas recovery, and migration prevention. The minister of petroleum has warned that pressure fall-off would begin in two years, should no compression project be implemented. Emphasizing the necessity of such a project, he has said that financial arrangements have been made for that purpose.

South Pars Development Status

South Pars consists of 28 production blocks that are being developed in 24 phases with a view to a total supply of 790 mcm/d of gas. Except for SP11, all phases of South Pars have been developed. SP11 lies along Iran’s border with the State of Qatar. NIOC signed, in 2017, an agreement with a consortium of France’s then Total, China’s CNPCI, and Iranian Petropars for SP11 development. But as the US reimposed sanctions on Iran’s oil sector, foreign companies pulled out. An Iranian company is developing SP11 whose first production commenced in 2023.

The gas produced at South Pars is delivered to the South Pars Gas Complex (SPGC). Of a total of 860 mcm/d of gas fed into Iran’s gas network, 590 mcm/d is supplied by SPGCwhich also yields 700,000 b/d of condensate, 20,000 tonnes a day of LPG, 1,500 tonnes a day of sulfur and 5,000-6,000 tonnes a day of ethane. Therefore, in addition to supplying national gas needs, it is a key contributor to the national economy. SPGC’s gas production is equivalent to 3.5 mb/d of crude oil.

WRFM to Help Prevent Oil Output Fall-Off

Artificial Intelligence (AI) is being widely used in the petroleum industry mainly due to the complicated nature and high costs of the industry, particularly in the processes of exploration, production, and operation. AI has grown into a key tool to enhance production, reduce costs, and realize more adaptation to environmental developments in the petroleum industry. In Iran, some steps have been taken in recent years and the Ministry of Petroleum and National Iranian Oil Company (NIOC) have adopted extensive plans in this regard. Pasargad Energy Development Company (PEDC), an Iranian energy holding, recently managed to launch the first phase of Well, Reservoir and Facility Management (WRFM) in the upstream oil and gas sector by spending $10 million.

Significance for Iran

In 2020, Ernst & Young (EY) conducted an opinion poll about investment by oil and gas companies in AI, whose results were interesting. The survey showed that 92% of respondent oil and gas companies had either already invested in AI or had planned to do so by 2022. According to this survey, about 50% of oil and gas industry managers use AI to overcome challenges in all their organizational processes in a bid to optimize their processes and reduce their costs.

PEDC, which has already invested heavily in the oil and gas sector and renewable energies, has focused on AI in the past year. In light of restrictions caused by sanctions, PEDC engineers developed WRFM to maximize production and recovery in a safe, sustainable, and cost-effective manner. Although Iran sits atop the world’s largest oil and gas reserves, because oil and gas fields are in the second half of their life, application of any method to enhance recovery or prevent fall-off would be vital. Increased oil and gas production capacity, increased hard currency revenue, bolstered energy security, increased competitiveness in global markets, foreign investment attraction, improved diplomatic ties, resilience to challenges caused by sanctions and job creation are some advantages of the WRFM process.

Details of Local WRFM

Construction of the first WRFM in Iran started in February 2024. It was launched in January 2025 as the first center in the upstream oil and gas sector.

PEDC’s WRFM is a management and technological structure in the upstream oil and gas sector. It uses a variety of tools, supervision and transmission operations, data analysis, and intelligent data processing for online management of operations pertaining to wells, reservoirs, and facilities.

WRFM is fitted with modern technologies including advanced sensors, data management systems, AI, and online data analysis in a bid to provide comprehensive data on the status of wells, flow of reservoir, and performance of facilities.

Investment in 2nd Phase

The second phase of this project aimed at completing drilling operation and engineering systems, well stewardship, and maintenance would need $5 million in investment shortly. Forecasts indicate that this investment would be provided by the Office of Vice President for Science, Technology and Science-Based Economy, NIOC, and PEDC for a year, which would facilitate access to applied digital transformation in the world-class upstream management of oil field development and production.

1st Phase Achievements

Online data gathering, storage and analysis, accessibility of updated data, integrated display system, observing data patterns and trends, and issuing necessary warnings, helping with quick and timely decisions in development and production operations, reducing operational risks, ensuring achievement of performance indicators, and the ability to access the company’s assets at any geographical location, and continuously optimizing the value of assets are among the goals achieved in the first phase of PEDC’s WRFM.

Other achievements of the first phase include preventing an output fall of 8,000 b/d and achievement of 1.4 mb total output, which would be valued at $100 million.

Key Goals in 2nd Phase

In The second phase of the development of this center, the existing systems will be made smarter by using machine learning methods, deep learning, AI models, and large language models. Smart optimization of production and flow assurance with smart monitoring of downhole pump operation, asphaltene sediment monitoring, pipe corrosion monitoring, completion of online hardware infrastructure, and smart maintenance and repair of facilities, as well as smart downhole operations, safety, production of drilling operations, and guidance of horizontal well drilling are also among the key objectives of the second phase.

Business Intelligence and AI

Furthermore, this project is considered one of the most important business intelligence projects. Business intelligence is a prerequisite for AI. Accordingly, projections indicate that artificial intelligence will be added to this center within the next calendar year to provide the necessary solutions.

It is important to note that such projects are carried out in most of Iran’s neighboring countries using the power of international companies, but in Iran, they have been carried out by domestic manpower. The first smart refinery is also planned to be built in Qeshm by PEDC.

Hossein Afshin, vice president for science, technology, and science-based economy, said in neighboring countries, such projects are operated using international firms’ capability while in Iran, local technology has been used. PEDC has now removed the barrier, thereby facilitating the job for other companies in this way.

Omid Shakeri, deputy minister of petroleum for research and technology, also said the Ministry of Petroleum was moving to support oil companies in using AI. “If these companies need support and facilitation we would help them move towards maturity.”

1-Offshore Exploration Resumes after 5-Year Hiatus

Mohi-ul-din Jafari, the director of exploration of the National Iranian Oil Company (NIOC), has said offshore exploration operations will resume soon.

Noting that the NIOC Directorate of Exploration had not had any offshore exploration drilling since 2019, he said offshore exploration would begin soon as contracts had been signed for rig supply.

He made the remarks during a ceremony for signing an MOU for joint exploration work with the Iranian Offshore Oil Company (IOOC) and two agreements with North Drilling Company (NDC) for offshore and onshore drilling rig supply.

He said that the NIOC Directorate of Exploration had a vast area of operation, adding: “In conducting geological, geophysical and drilling studies, the focus of this Directorate has been on the onshore sector due to restrictions with rig supply.”

Since the 2nd National Development Plan, the NIOC Directorate of Exploration has averaged 6 drilling rigs per year.

“Today, with the assistance of the CEO of NIOC, the rig count is set to rise. Energy Sina is providing five onshore and one offshore rig, accounting for 70% of the onshore and offshore rigs of this Directorate. Moreover, nearly 70% of the drilling budget in exploration drilling is supplied by this holding,” said Jafari.

Referring to the NIOC-IOOC memorandum, he said joint exploration work was planned. He added that seismic testing at the Nosrat field was a case in point.

Jafari said NIOC’s subsidiaries would be hired to develop exploration, adding: “We’re trying to increase the NIOC Directorate of Exploration’s drilling rig count to 12. When rig count rises, the pace of onshore and offshore exploration would double while timing would be shortened.”

He said that Sina Energy would soon start its work in the offshore exploration drilling sector in the Persian Gulf, expressing hope for Sina Energy’s involvement in geophysical studies.

The MOU between the NIOC Directorate of Exploration and IOOC was signed by Jafari and CEO of IOOC Ahmad Reza Rasti for cooperation in drilling, seismic testing, and geophysical studies.

Jafari and Rouhollah Abdi, the acting CEO of NDC, signed two agreements for offshore drilling rig procurement and an addendum for increasing the onshore drilling rig count.

2-RIPI Seeks Role in Intl. Fora

The director of the Research Institute of Petroleum Industry (RIPI), Azim Kalantari Asl, has said RIPI was trying to boost its international role.

He said RIPI had received two international awards in as many years, adding: “What are looking for, is to enhance our role at the international level in a bid to preserve scientific chares and strongly support political decision-makers.”

He said that one prize had been awarded on the sidelines of the Algiers summit of the Gas Exporting Countries Forum (GECF) last year and the other award pertained to RIPI’s environmental activities. The second one was awarded during the prime ministerial meeting of the Eurasian Economic Forum 2024 in Armenia.

Touching on RIPI’s role in gas discovery, he said: “Over the past 15 years, we have had a good performance concerningthe discovery of reservoirs. Hydrocarbon reserves are divided into conventional and unconventional. For instance, the South Pars or Kangan fields are conventional while shales or hydrates are considered unconventional.”

Explaining RIPI’s measures for enhanced recovery from oil wells, he said: “In cooperation with NIOC in former field-oriented projects, currently known as technological projects, we have a pilot project for water injection into the Bangestan layer of the Ahvaz field. It has to be noted that we have some experience in offering water injection, but when it comes to onshore, except for the Azadegan field, we have no such experience.”

“The stages related to laboratories, services, designing, and simulating water injection have gone ahead with the cooperation of National Iranian Oil Company (NIOC) and National Iranian South Oil Company (NISOC) and we hope to finish the final injection plan at a specific level of this field, which would be highly effective if proven successful as in some fields, it would be possible to inject water instead of gas.”

“In this regard, we carried out the first national injection in offshore oil in a field with preliminary results proven to be successful. We need to do more for this project to become more fruitful,” he said.

Kalantari also referred to other RIPI’s upstream projects including drilling mud and cement, saying: “One of our specific challenges in the future would be water projection at fields, which would be followed by output fall in addition to environmental consequences. For this reason, if we manage to minimize water production from wells by technological development, it would be strongly in the prospective interests of the country. At RIPI, we have developed three specialized technologies and we are ready to implement this project.”

3-NISOC 80% Self-Sufficient in Manufacturing

EbrahimPiramoun, CEO of the National Iranian South Oil Company (NISOC), has announced 70-80% self-sufficiency in local manufacturing of commodities required by this company.

“Fortunately, over the past years, we have improved valuably in terms of manufacturing petroleum industry equipment such that we have left behind the phase of part manufacturing to enter the equipment manufacturingprocess,” he said.

“Exhibitions on petroleum industry equipment manufacturing play a fundamental role in supporting oil production in areas run by NISOC as the largest oil producer in Iran,” he said.

Piramoun said NISOC had the highest number of equipment used in the Ministry of Petroleum’s production and upstream sector, adding that these installations are scattered across NISOC-run areas.

He said that NISOC was using various equipment, including instruments, mechanical and rotary equipment, and pipelines in various sizes and specifications.

Referring to NISOC’s mission to preserve a 75% share of national oil production, he said: “Our equipment is very aging and decrepit due to sanctions. Petroleum industry equipment manufacturers and knowledge-based companies build a variety of equipment for the petroleum industry and they can help us effectively.”

He said that NISOC took pride in the domestic manufacturing of turbines, pumps, and other equipment in the petroleum industry. He added that NISOC could support these first-time manufacturers and suppliers to churn out production.

Piramoun expressed hope that manufacturers would go ahead in line with technological progress in the world so that the share of self-sufficiency would increase in coming years.

Emphasizing the necessity of manufacturing high-quality commodities by local manufacturers, he said: “Quality is a key element to be taken into consideration by manufacturers. We are crossing the phase of part and equipment manufacturing. Therefore, manufacturers should apply new technologies to boost quality so that domestically manufactured equipment and parts could rival foreign prototypes.”

4-Private Sector Given 100 Investment Packages

Hamid Bovard, CEO of the National Iranian Oil Company (NIOC), has said five oil projects are ready to come online, adding that 100 packages of investment in the petroleum industry will soon be presented to the private sector.

He said the package would allow the domestic and foreign private sectors to increase oil and gas production.

Bovard said the Ministry of Petroleum was committed to increasing Iran’s oil production by 250,000 b/d by March 2025, adding: “Effective steps have been taken in this regard and we will reach this output hike by the end of the calendar year.”

He said that the oil production hike over the past four months was due to efforts made by NIOC’s subsidiaries, adding that the Khesht oil field had been developed in the southern province of Fars, while a second well had become operational in the Dey gas field.

Bovard said gas production hit record four times under the 14th administration, adding that gas output reached1.104 bcm/d.

Underscoring the necessity of energy efficiency in Iran, he said no concrete decision had been made regarding gas consumption.

Bovard said five oil projects were ready to come online, enumerating them as the Varavi gas compressor station, the 110,000-barrel Ahvaz centralized desalination plant, the Azadegan field’s CTEP, Gachsaran gas injection, and Rag Sefid associated gas gathering.

He said that numerous gas-gathering projects had been designed, which would allow for capturing 20 mcm/d of flare gas by next spring.

Bovard said the Rag Sefid gas gathering project would allow for capturing 5 mcm/d of flare gas.

5-Onshore Oil/Gas Fields Output Up

The CEO of Iranian Central Oil Fields Company (ICOFC), Peyman Imani, said the company had managed to enhance gas production from onshore fields by 10 mcm/d and crude oil production by 13,000 b/d over four months.

“Some of the measures taken have been:the operation of the Varavi gas compressor station with the normal operating capacity of 7 mcm/d, which could be raised to 9 mcm/d, completion and installation of wellhead installations at 6 gas well sites of the Dalan, Aghar, Tang-e Bijar, Dey and Khangiran fields, building access roads to wells of the Khar Tang gas field, preparing the site of Well No. 2 of the Sarajeh storage site in Qom, conducting numerous technical and operational operations on wells for maintenance of winter production levels and embarking on the integrated management project of the Tang-e Bijar reservoir and satellite wells in collaboration with the ShahidChamran University for gas output hike .”

Imani said simultaneously with gas production by ICOFC, effective measures have been undertaken for crude oil production. “Commissioning the Khesht filed oil production plant at 10,000 b/d capacity, operating three wells of the Dehloran oil field with 3,000 b/d capacity, commissioning four wells of the Khesht oil field, and starting up a crude oil pipeline extending from the Khesht field to consumers are among measures taken in this domain.”

The ICOFC managing director said the company was active in 14 provinces, running 87 oil fields containing 102 reservoirs.

“In addition to production, thanks to its good performance in previous years, ICOFC has fared well in hydrocarbon field development, the most important of which has been the construction of the Varavi gas compressor station,” he said.

Imani said developing 16 gas fields is underway by private contractors and investors, some of which are Halegan, Eram, Pazn, Gordan, Aghar, and Tang-e-Bijar.

He referred to an additional 10,000 b/d crude oil production from the Dehloran and Khesht fields, adding: “Development of the Saman, Sumar, and Delavaran oil fields would be awarded soon to an Iranian company under IPC terms. Production from these small fields would add 9,000 b/d to national oil output.”

Regarding enhanced gas production from the Tous field in northeastern Iran, he said: “So far four wells have been drilled at this field and a contractor has been chosen for its 4 km pipeline.”

6-$120bn Investment in Oil, Gas Sector Needed

Minister of Petroleum Mohsen Paknejad has said a $120 billion investment would be needed under the 7th National Economic Development Plan to boost oil and gas production capacity.

“In implementing development projects, in addition to increasing capacity, oil and gas production fall should be prevented,” he said.

He added that despite economic restrictions, the Ministry of Petroleum was combatting on the frontline of ongoing economic warfare.

The minister gave a positive assessment of the petroleum industry, saying: “During the couple of months since the 14th administration took office, 60,000 b/d has been added to national crude oil production capacity and 30 mcm/d to natural gas production capacity.”

In coincidence with boosting feedstock supply to refineries, he said, gasoline and gasoil output grew 10 ml/d and 11 ml/d, respectively. He added that increased petroleum products supply had saved on hard currency spending.

Paknejad said two parameters were involved in the issue of energy carriers’ shortage: production and consumption management.

“The first parameter is enhanced production. For natural gas output hike, we are planning gas compression at South Pars,” he said. He added that the South Pars compression project would have seven hubs, each requiring $2.5-3 billion. The minister said the project would need a total of $18 billion in investment.

He said some projects had been drawn up for crude oil production lift under the 7th Development plan. “In a bid to reach 4.6 mb/d crude oil production capacity by the end of the 7th Plan, about $50 billion in investment would be needed.”

“Furthermore, under the 7th Development Plan, natural gas production capacity should increase to 1.350 bcm/d, for which $75 billion in investment would be needed,” said the minister.

7-Infill Project 1st Gas Well Due Soon

TourajDehqani, CEO of Pars Oil and Gas Company (POGC), has said the first gas well in the infill project of the South Pars gas field would become operational soon.

He said that drilling in South Pars had accelerated, as four drilling rigs were operating there.

Dehqani said another three rigs were operating in other gas blocks, adding that the pace of drilling would accelerate.

The Sahar 1 and Pasargad 200 drilling rigs were installed in the gas blocks of Platforms 19A and 19B of South Pars, he said, adding: “Now the number of drilling rigs operating in the infill project has increased to four. That is an important step in construction work in the third and fourth packages of well drilling in the South Pars gas field.”

Drilling would start after preparations have been made, said Dehqani, adding that gas production had to remain stable to prevent any halt in energy supply.

He said the Sahar 1 and Pasargad 200 drilling rigs had been installed on the two gas platforms in the shortest possible time.

Four packages of the infill project are now fully operational, he said, adding that the first well drilling would be completed soon.

Dehqani said 35 wells were planned to be drilled across the South Pars gas field, which leads to increased production from South Pars.

“This is a key plan by the National Iranian Oil Company (NIOC) for maintaining the production capacity of the South Pars reservoir. It would be playing a key role in managing gas imbalance in the coming three years,” he added.

He said the infill wells would be drilled in 17 gas platforms, which would finally enhance gas production capacity in South Pars by 36 mcm/d.

8-SP 4th Refinery Supplies 220,000 Barrels Condensate

BehzadSalari, the director of the fourth refinery of the South Pars gas field, has said the facility produced more than 220,000 barrels of condensate during the first three quarters of the current calendar year.

He said the foregoing figure was achieved using innovative know-how and fully Iranian commodities. He added that the fourth refinery had played a key role in Iran’seconomic prosperity.

“Following high-quality maintenance and innovative measures by local staff and specialists, more than 10 mt of ethane was produced during the 9 months,” he said.

Salari said that 2 bcm of gas had been processed at the refinery during the period, leading to the supply of 360,000 tonnes of propane and 240,000 tonnes of butane.

“In the latest measure, in cooperation with the Directorate of the second district of gas transmission and electricians of the 4th refinery, five gas export turbines were repaired,” he added.

“Implementing and finalizing safety studies on the refining process, identifying processing quantities and planning for the removal of faults, separation of industrial from non-industrial zones, repairing local fences, and treating contaminated soil of industrial zones in line with Clean Weather Act are among outstanding activities of the HSE sector,” he added.

9-Sweet Gas Output 22 mcm/d More Than Planned

Saeed Tavakoli, CEO of National Iranian Gas Company (NIGC), said sweet gas supply during winter reached 872 mcm/d, up 22 mcm/d from what had been planned.

“Initially, NIGC had been instructed to produce 850 mcm/d gas for feeding the national distribution network;however, in some days, we hit 872 mcm/d,” he said.

He added that some measures taken in the gas transmission network, such as using turbocompressors, avoided the retention of 50 mcm of gas.

“Despite financial restrictions, NIGC has gone well beyond its obligations. For instance, it issued permits for underground gas storage at salt domes, instructed completion of Iran Gas Trunkline 9 (IGAT-9), and earmarked IRR 12 trillion to building capacity for renewable energies and energy efficiency,” said Tavakoli.

“If the Ministry of Petroleum intends to be a fuel supplier it would need an industrial development strategy. For instance, a steel manufacturing plant could not be set up in central Iran to deliver its products to the north and on to the south for export,” he said.

Touching on the necessity of attention to an industrial strategy in Iran and the importance of integrated energy management, he said: “Good prioritization has been done and NIGC has overcome restrictions.”

“There are three gas transmission and refining indicators: reliability, accessibility, and applicability. Under the 14th administration, all these indicators have been on an upward trend,” he said.

10-Abadan Gasoline Output Set to Grow

FardinRashedi, CEO of the Abadan oil refinery, said the facility would increase its gasoline production by 8-10 ml/d in the coming months.

“Over the coming 40 months, all products at the Abadan refinery would see their quality improve,” he said.

“The Abadan refinery is a symbol of Iran’s civilization in the oil industry. The first distillation unit of this refinery became operational in 1912. The refinery has gone through four different historical periods, such as the First and Second World Wars, the imposed war, and the glorious Islamic Revolution. The refinery is also currently the main axis for supplying products and eliminating imbalances in the country,” he added.

Rashedi referred to the 210,000-barrel distillation unit of the refinery and the operation of the Middle East’s largest hydrocracking unit in the Abadan refinery, saying: “By commissioning the hydrocracking unit of the Abdan refinery, gasoil would be produced in line with Euro-5 grade and the products’ quality would be upgraded.”

“So far, more than €1.2 billion has been invested in the Abadan refinery’s capacity maintenance. This project is a major national project that would result in the most sophisticated units at this facility in the future,” he said.

He said efforts were under way for all units of the Abadan refinery to be upgraded in quality over 40 months, adding: “That would allay concerns about fuel oil supply to power plants. Meantime, upgrading the quality of the last desulfurization unit would be planned.”

While highlighting the geographical position and the historical background of the Abadan refinery,Rashedisaid social responsibility had always been considered by this facility.

“All projects carried out at the facility comply with environmental considerations. In this regard, we’re trying to replace ethanol in a bid to reduce pollution,” he said.

11-Petchem Exports Yield $10bn in 9 Months

HassanAbbaszadeh, CEO of National Petrochemical Company (NPC), has said petrochemical exports during the first three quarters of the current calendar year produced $10 billion.

He said petrochemical earnings would have totaled $13 billion by the end of the current calendar year.

“Currently, 85% of the petrochemical industry is concentrated in holdings, mostly affiliated with pension funds and 15% is privately-held,” he added.

Abbaszadeh said 61 petrochemical projects had been defined under the 7th National Economic Development Plan, adding the 7th Plan had focused on value chain completion in the petrochemical sector.

“The 7th Development plan is divided into value chains and reaching 131.5 mt capacity by 2028 in the methanol, polyethylene, and ethylene chains,” he said.

“That has made the job tougher, but it would help move towards chain completion and supply of higher-valued products,” said Abbaszadeh.

He said the main challenge to the petrochemical industry in implementing projects was financing, adding: “Implementing petrochemical projects under the 7th Development Plan would require $24 billion in investment. $12 billion has already been allocated and the projects are 50% completed. Another $12 billion would be invested.”

Noting that the 8th Development Plan’s projects were at the beginning of the road, he said: “To stabilize petrochemical feedstock supply, investment has been done by petrochemical companies for flare gas capture.”

Abbaszadeh said: “To engage petrochemical companies and holdings in small gas fields’ development, MOUs have been signed and some companies have prepared contracts to produce more gas and remove the challenge of feedstock supply.”

He said that the petrochemical industry had also engaged itself in energy efficiency, offering services to several cold cities.

Bandar Abbas Oil Refinery Gets Supply Line

On 29 December 2024, a pipeline feeding the Bandar Abbas oil refinery (branching out from the Goreh-Jask pipeline) became operational with 300,000 b/d capacity to help stabilize output and develop strategic infrastructure in Iran.

Mohammad Sadeq Azimifar, CEO of National Iranian Oil Refining and Distribution Company (NIORDC), said completion of the project would allow for the supply of 300,000 b/d of crude oil as feedstock to the refinery, which would be an effective step in increasing refined production.

Refineries are tied to national economic development plan and their strategic importance is no secret to anyone. These structures play a pivotal role in the oil and gas value chain. They advance the interests of both producers and consumers in addition to providing the best possibility for national development. Therefore, strategic investment in refineries would result in refined products of higher value.

Oil and gas pipelines are lucrative man-made structures that can carry massive volumes of fluid products. The most important section of infrastructure in the developed oil, gas, and petrochemical industry and equipment is the existence of extensive networks in which such pipes are used.

Azimifar said a key challenge to feeding refineries has been the dilapidation of oil tankers and climate impacts, which reduced feedstock supply and subsequently output fall. Therefore, commissioning this pipeline would guarantee persistent feedstock supply in favor of lower dependence on maritime transport.

Quality Upgrade

The Goreh-Jask crude oil pipeline is highly significant from another aspect, i.e. feedstock supply to refineries. The Bandar Abbas oil refinery is the sole facility processing heavy and extra-heavy crude oil in Iran. It also accounts for 15% of Iran’s refining capacity. It was built in 1992 on 700 ha of land to process extra-heavy crude oil and export products. The facility came online five years later with a 230,000 b/d capacity. Today, the Bandar Abbas oil refinery remains one of the largest refineries in Iran. Over recent years, it has managed to bring its refining capacity to 350,000 b/d.

The other issue is the global significance of this refinery. The refinery recently won praise for its carbon footprint performance as it cut 35.42% of its GHG emissions by changing its feedstock. It was awarded Carbon Saving and Green CSR Label certificates.

Ahmad Hashemi, CEO of Bandar Abbas oil refinery, said before the new pipeline became operational, about 93% of the feedstock for the facility came from Kharg, 6% from Assaluyeh, and a little from Sarkoun and Hengam.

Referring to unfavorable weather conditions and decrepit vessels as the main challenges to feedstock supply to the Bandar Abbas refinery, he said: “In some cases, we had to cut out feedstock to one-third. Moreover, feedstock supply by vessel is highly risky in terms of economics. On several occasions, due to the untimely supply of feedstock, we were close to shutting down the refinery.”

To overcome these challenges, a contract was signed in November 2020 for building a 37 km-long pipeline of 30-inch diameter branching out from the Goreh-Jask pipeline. Construction lasted 16 months until it came online with a capacity to handle 300,000 b/d under conditions of sanctions. Therefore, the pipeline feeding crude oil to the Bandar Abbas refinery is highly significant and will be instrumental in the economic development of this area. Bandar Abbas remains a key industrial and academic center tasked with supplying necessary raw materials to petrochemical plants and refineries. The new pipeline would reduce road or maritime transport risks, subsequently reducing hazards associated with the transfer of raw materials and most importantly environmental pollution while improving security for feedstock supply. This pipeline will also help economic prosperity and job creation in this area because industrial facilities would depend on this pipeline which would directly and indirectly create jobs.

Another issue is that owing to its geographical position and access to the high seas, Bandar Abbas is seen as a strategic spot for exporting petrochemical and petroleum products. The pipeline facilitates sustainable feedstock supply for export.

Therefore, the operation of this pipeline would secure energy in the country and offer a reliable and safe route for crude oil transfer and fuel supply under critical conditions, which would finally make up for the energy imbalance in the country.

First Cargo Loaded

Mohammad Meshkinfam, CEO of National Iranian Oil Refining and Engineering Construction (NIOEC), said construction on this project started in June 2023 and lasted 16 months. Recently, the first oil cargo was delivered to the Bandar Abbas refinery.

Hashemi said the pipeline would be key to resolving the fuel imbalance in Iran, adding NIOEC was tasked in 2019 with building 37 km of this pipeline. He added that 5.5 km of the pipeline was financed by the refinery. Construction of this pipeline would save more than $80 million spent on carrying feedstock from Kharg to Bandar Abbas. By connecting the Bandar Abbas refinery to this pipeline, feedstock supply to the treatment facility would be guaranteed constantly for the first time with no fear of disruption. It would boost productivity while reducing costs and boosting energy security.

Regarding the significance of the project, he said: “This project is highly significant for the Bandar Abbas refinery in economic, strategic, and environmental terms. It marks a turning point in the development of infrastructure for feedstock supply to this refinery.”

Last August, Hashemi touched on challenges to feedstock supply to the Bandar Abbas refinery, saying: “Crude oil supply to the refinery as feedstock by maritime routes is faced with many challenges, including unstable and unfavorable weather conditions and oil tankers docking at Kharg, which would delay feedstock supply to the refinery. Such problems would result in lower crude oil storage and increased risk in product supply.”

Refineries would be instrumental in the hydrocarbon value chain in the future. Their performance directly impacts the energy security and economic well-being of countries. Striking a balance of interests between oil and gas companies, fuel consumers and society would require optimization of refineries.

The Public Relations Office of Iran Oil Pipeline and Telecommunications Company (IOPTC) has announced that during the second four-month period of the current calendar year, more than 22.557 billion liters of petroleum products and 24.85 billion liters of crude oil was distributed across the country by pipeline. It was up 4.4% year-on-year. Now, the new pipeline project would add 300,000 b/d to the petroleum product supply.

Moreover, in light of the safety and stability of fuel transmission across the country, particularly during cold months, 1.357 billion liters of liquid fuel was delivered to power plants during the same four-month period this calendar year.

Therefore, strategic infrastructure development, technology modernization, digitalization, automation, and lateral integration can help refineries enhance balancing attributes while creating future-ready, sustainable systems. Ultimately, targeted investments in refinery assets will lead to balanced progress. Investment in maintaining and upgrading oil, gas, refining, and petrochemical complexes, including facilities and transmission pipelines through preventive maintenance and inspection, modification, and renovation measures, is a necessity to maintain production, optimize consumption costs, reduce risks and accidents, and most importantly, utilize the resources and capabilities available in the country.

Oil 2024, Quick Review

Pouneh Torabi

The world oil market did not experience much volatility in 2024. North Sea Brent traded between $83 and $85 a barrel in the 1H2024, which was weakened to even $71 a barrel during the third and fourth quarters due to lower demand.

In general, oil prices varied between $70 and $85 a barrel through 2024, following a sideway trend and indicating market stability and limited price variations throughout the year. On the one hand, overproduction kept prices from growing while on the other, flexibility in supply by OPEC and shale producers blocked any price fall.

Due to its market nature and dynamics, oil prices are prone to significant fluctuations and directly and indirectly impact the global economy and social welfare. These fluctuations depend on various factors, including supply and demand, OPEC policies, the global economy, geopolitical developments, climate change, and alternative energies.

Goldman Sachs, an investment bank, expects oil demand to continue growing for another decade, driven by rising total energy demand alongside GDP growth, and the ongoing challenges of decarbonizing air travel and petrochemical products.

Therefore, oil supply and demand, and its price, continue to affect human fate, which explains why it is subject to speculation.

2024 Supply / Demand

In the final days of 2023, the International Energy Agency (IEA) forecast a balanced supply-demand ratio in 2024, holding out the possibility of minimum supply in the 1H2024. For its part, the Organization of the Petroleum Exporting Countries expected oil demand to grow 25.2 mb/d in 2024 to bring global oil demand to 104 mb/d, while the IEA expected oil demand to grow 2.1-3.1 mb/d to lift oil demand to 103 mb/d.

Data show that oil production reached 101-103 mb/d in 2024, mainly driven by higher supply by non-OPEC nations and decisions adopted by OPEC+ to keep supply in check. Global oil demand reached 102-103 mb/d, mainly driven by economic growth in Asian nations, particularly China and India. The increased demand resulted from post-pandemic economic recovery, higher consumption in transportation and industrial sectors, and renewed demand by developing countries. In the meantime, changes in energy policies and lower oil consumption in some developed nations caused demand to fall.

Market Changes

OPEC and OPEC+ decisions on increasing or decreasing oil supply are the most effective in the market status. To that effect, their decision to cut output to control prices helped perpetuate market stability.  In April 2023 and November 2023, the countries announced additional voluntary adjustments. The countries decided to extend the additional voluntary adjustments of 1.65 million b/d announced in April 2023, until the end of December 2026. But despite OPEC cuts, shale oil production in the United States kept growing in 2024, which is expected to follow suit in 2025.

In the meantime, as the leading oil importer, China experienced the weakest economic growth in 2024, leading to lower global demand for oil because of demand volatility, even a freeze by this country would bring oil prices down. China experienced slower economic growth in 3Q2024 year-on-year. Official data show the world’s second-largest economy grew 4.6% from July to September, well above the Reuters poll’s 4.5% forecast but below the 2Q’s 4.7%.

In Europe and America, economic stagnation and higher interest rates in 2024 reduced energy consumption. But India and Middle Eastern nations, as major consumers, recorded higher demand to offset lower demand by other countries.

Politics Haunting Oil

Political relations between countries continued to cast a shadow over oil in 2024, as regional conflicts between Iran and the Zionist Regime and concerns about disruptions to oil flows through the Strait of Hormuz temporarily boosted prices.

Meanwhile, the war between Ukraine and Russia continued and new sanctions on Russia affected its oil exports, ultimately allowing Russia to sell its oil to Asian countries at a discount.

Saudi Arabia, the world’s largest oil exporter, continued its policy of production cuts in 2024. Saudi oil revenues fell to their lowest level in three years in June following supply reduction by OPEC and OPEC+. Official statistics indicate that Saudi Arabia earned $17.683 billion from oil sales in June, down 12.6% from May 2024 and the lowest since August 2021. OPEC data show that Saudi Arabia’s June oil output averaged 8.93 mb/d, down from 9.01 mb/d in May.

Russia was under a Western embargo due to its war on Ukraine. However, it managed to maintain its oil exports to Asian nations like China and India at discount prices. Kepler, a research institute, has reported Asia’s seaborne oil imports from Russia, known as the second largest oil exporter in the world, were down to 161.200 million tonnes in 2024, falling from 2023’s 170.600 million tonnes.

The US also increased its shale oil production to 13.200 mb/d. Canada, a top oil producer, did not change its oil production significantly and kept its output at 4.6 mb/d.

Iraq has tried to keep complying with the OPEC deal. It produced 3.940 mb/d of oil in September, below the 4 mb/d quota agreed with OPEC and allies.

Venezuela’s 2Q oil production was up 4.62% from the first quarter to 922,000 b/d. OPEC named Venezuela as the second largest crude oil extractor in June.

Iran Output

Iran’s petroleum industry has been subject to tough sanctions in recent years. They started with limiting oil companies’ presence in Iran’s oil sector until Donald Trump attempted during his first term in office to zero Iranian oil exports.

The latest report by the OPEC Secretariat shows that Iran’s September oil production was up 21,000 b/d. Iran accounted for the highest oil production among fellow members in September. Data released by the US Energy Information Administration (EIA) also confirm Iran’s increased share of global crude oil supply.

The EIA report said Iran’s share in global crude oil production reached 4.3% during 3Q2024. During the corresponding period a year before, Iran’s share stood at 3.9%. For the entire 2023, the share was again 3.9%.

The EIA indicated that Iran produced 4.42 mb/d of crude oil and condensate in the first quarter of 2024, up from 3.99 mb/d a year before. That shows 8.8% growth while OPEC’s overall oil production growth was 0.8% during the same period. It shows that Iran accounted for 13.8% of OPEC’s 1Q production and ranks third among fellow OPEC producers. In 2023, Iran had a 12.6% share of OPEC’s oil output.

Price Curve

Brent prices rose sharply after falling to a six-month low of nearly $75 in early June, reaching around $89 per barrel by early July. The June price decline was driven by the imminent end of the OPEC+ voluntary supply cuts and weaker expectations for global economic activity. Declining refinery margins have raised expectations of lower refinery capacity utilization and lower crude demand.

The price hike was bolstered by OPEC+’s decision in early June to extend voluntary cuts until October and further cuts until the end of 2025. Geopolitical tensions in the Middle East were also ramped up.

Average Brent prices were broadly stable in 1H2024, hovering between $83 and $85 a barrel. However, this relatively stable seasonal trend masked short-term volatility as regional instability and economic challenges continued to drive price volatility. This volatility was particularly evident in 3Q2024.

The price hike trend was reversed in early August, with Brent falling to $78 a barrel. Weak seasonal demand for gasoline in the US, lower than in pre-pandemic years, and weaker-than-expected global economic indicators added to the downside pressure. Rising interest rates in Japan, continued weakness in the Chinese economy, and slowing job growth in the US weighed on upside risks from unrest in the Middle East.

Prices returned to $83 by mid-August and remained above $80 through September as peak summer demand, coupled with tight OPEC+ supply, led to a relative drawdown of global inventories. Ongoing fighting between rival factions in Libya for control of the central bank shut down production and export facilities, removing half of Libya’s crude output from the market.

Brent prices fell below $72 in the first two weeks of September, their lowest since December 2021. The $8 drop was driven by expectations that OPEC+ voluntary cuts would be lifted in October, which were estimated to be reduced by 180,000 b/d. Hopes for political stability in Libya also intensified the market pressure, deepening the price decline. The end of the driving season in the US and weak production data from China reduced market confidence in future demand. OPEC+’s announcement to extend voluntary cuts until the end of November also failed to prevent prices from falling.

Renewables, Key Energy Players in 2025

Elaheh Baqeri

The year 2024 ended with the global gas market exposed to new experiences and wide price fluctuations. In continuation of 2023, 2024 saw growing gas demand with LNG prices up. According to a report by the Organization of Arab Petroleum Exporting Countries (OAPEC), liquefied natural gas (LNG) exports grew 1.9% from January to September year-on-year to 100.9 mb/d. The Organization of the Petroleum Exporting Countries (OPEC) estimated that the United States remained the world’s top LNG exporter in 2024, followed by Australia and Qatar. In 1H2024, Russia increased its LNG exports to Europe by 16%, equivalent to 2 bcm.

In its recent report, the International Energy Agency (IEA) forecasted that world gas demand will reach an all-time high in 2025 driven by growth in Asia, but delays to new LNG production will curb supply.

Gas demand, especially in Europe, fell sharply in 2022-23 as prices soared following the loss of large volumes of Russian pipeline gas supply due to the war in Ukraine.

This increased the demand for globally traded LNG put Europe in direct competition with Asian buyers.

According to the IEA report, global gas demand for the full year 2024 is expected to grow by just over 100 bcm, or more than 2.5%, to a new all-time high of 4,200 bcm.

In 2025, demand would grow another 100 bcm, or 2.3%, to a fresh high, driven predominately by economic expansion in fast-growing Asian markets.

“However, the global gas balance remains fragile as limited growth in LNG production is keeping supply tight, while geopolitical tensions continued to cause price volatility,” said the IEA report.

Gas demand in OECD Europe is forecast to decline by 2% this year due to lower use in the power sector, but to rise by 1% in 2025 as the building, commercial and industrial sectors use more gas.

At the same time, global LNG supply is expected to grow at its slowest rate since 2020 of just 2%, or 10 bcm.

LNG supply growth is set to accelerate to 30 bcm, or nearly 6% in 2024, as several large LNG projects, particularly in the United States, come online.

The IEA’s forecast indicates another challenging year for Europe where consumers will face high bills.

Energy security balance with energy transmission objectives requires addressing short- and long-term needs. Oil and gas will continue to remain key factors in the global energy mix for decades. Oil demand is largely expected to peak over the coming decade.

According to Rystad Energy scenarios in 2024, more than 90% of the world’s population live in areas where they can meet their future energy needs from renewables. More than 80% live in countries highly dependent on fossil fuel imports.

Challenging Elections from East to West

Another remarkable point in 2024 was general elections held in many countries in the world. More than half of the world’s population in 64 countries went to the polls. Taiwan, Bangladesh, Pakistan, Russia, India, Mexico, Iceland, Belgium, the US, and the European Union were cases in point. Iran and the US held three elections each. Iran held presidential, legislative, and Assembly of Experts elections while the US held presidential, Congress, and Senate votes.

The important point of the elections is the decisions and approach that the newly elected officials have taken or are taking towards fundamental issues in the world, such as climate change, energy transition, renewable resources, fossil fuels, and greenhouse gas GHG emissions.

Energy Transition Promises

A significant portion of the energy needs of countries is supplied by fossil fuels, but due to the increasing population growth and increasing demand for energy around the world, the available reserves of fossil fuels are decreasing. On the other hand, these fuels cause a lot of environmental pollution, which ultimately

leads to climate change, the extinction of important animal and plant species, droughts, or heavy floods. Therefore, one of the smart and appropriate solutions is to transition from fossil fuels to renewables. Renewables provide a decentralized, stable, and local energy source, reducing dependence on global markets and improving energy security. The New Year, therefore carries a heavy responsibility to seize this opportunity. Indeed, governments must seize this opportunity in 2025 and commit to bold actions that will accelerate the transition to a sustainable energy future.

This issue has been of interest to many countries for several years, and the international community has taken this issue seriously since the 2015 Paris Climate Change Conference. In late 2023, the annual climate conference known as COP28 was held in Dubai, and strategic goals for 2030 were set, such as gradually reducing coal fuel, eliminating fossil fuel subsidies, and reducing methane emissions. COP29 was held last year in Baku, Republic of Azerbaijan, to discuss the future of energy.

One outcome of the conference was a commitment by developed countries to provide $300 billion in annual climate finance by 2035, three times the current target, although still far short of the $1.3 trillion per year requested by developing countries. The commitment aims to support emerging economies in shifting from fossil fuels, build flexibility to climate impacts, and address the losses and damages caused by natural disasters. This is a positive step, however, as always, the real challenge lies in translating these commitments into concrete and measurable actions.

Another issue regarding global gas markets in 2024 was increased LNG exports by the US. Preliminary data from financial firm LSEG showed US LNG exports reached near record levels in December, rising to 8.5 million metric tonnes as two new plants, opens new tab started, and driving up full-year shipments by 4.5% over 2023. For the year, LNG exports hit 88.3 mt, up from 84.5 mt in 2023, ensuring the US maintained its crown as the world’s largest LNG exporter.

US President Donald Trump has said he will focus on boosting oil and gas production when he returns to the White House in January. He has also shown strong support for the oil and gas industry by pledging to make it easier for energy companies to obtain drilling permits and develop energy infrastructure. Other policies are likely to include allowing energy companies to export more natural gas and increasing drilling in federal lands.

2025 Outlook

Morteza Behrouzifar, a senior member of the Institute for International Energy Studies (IIES), told Iran Petroleum: “Given Donald Trump’s remarks, US gas production will go on and this country’s clout with the global gas market will keep growing.”

He said that the US would enhance oil and gas production under Trump, adding: “Since Russia’s gas ties with Europe have declined, Europe is trying to find countries other than Russia to supply its gas needs.”

“Over the last two or three years, we have also had tensions between Ukraine and Russia, following which Ukraine has threatened not to renew the gas transit contract, and therefore, Russian gas exports to Europe will decrease in 2025. All these things have created and will continue to create widespread changes in the region,” said Behrouzifar.

Ukraine recently halted Russian gas supplies to European customers through its pipeline network after a prewar transit deal expired at the end of 2024 almost three years into Moscow’s all-out invasion of its neighbor. Russia shipped about 15 bcm of gas via Ukraine in 2023, down from 65 bcm when the last five-year contract began in 2020.

Russia and the former Soviet Union spent half a century building up a major share of the European gas market, which at its peak stood at around 35%. However, the EU has slashed its dependence on Russian energy since the start of the war in Ukraine by buying more piped gas from Norway and LNG from Qatar and the US.

Behrouzifar said given the situation that occurred in Europe after Russia’s invasion of Ukraine, all European countries, as well as the entire world, moved towards increasing the consumption of renewable energy and energy transition.

“The share of renewables in the global energy mix is ​​expected to increase by 2025. Overall, both increased US gas production and increased renewable energy production and share are expected to disrupt the global market,” he added.

Referring to increased investment in the oil and gas sector, Behrouzifar said: “Given the conditions in Russia and the decline in gas exports from this country to Europe, and Trump’s presidential victory, it seems that the volume of investment in the US gas market will increase; especially if we look back at Trump’s previous presidential term, one may notice that he has always sought to increase domestic production in the US and has proposed plans in this regard during this period as well.”

“Therefore, we will see an increase in US oil and gas production, but in European and East Asian countries, the focus seems to be on renewable energies, because at the European level, due to existing problems, there are no conditions for increasing production, and on the contrary, an increase in demand is seen. That’s why in European and Southeast Asian countries, we will have more investments in renewables,” he said.

Iran Untapped Potential

Behrouzifar said Iran would need to communicate with the world and see sanctions lifted.

“It is necessary to thoroughly remove the shadow of sanctions from Iran’s oil and gas to achieve real development of this industry. If the sanctions are completely lifted, the way for foreign capital, first-tier countries, and global technologies to enter the country will be opened,” he added.

Touching on Iran’s potential in attracting foreign investment in the energy sector, he said: “Iran is a country that has all the requirements to attract foreign investment; from a young, educated workforce and scientific knowhow and capacity, to significant land and sea routes, infrastructure, and oil and gas reserves that have not been sufficiently invested in for years.”

But, he noted, the first condition would be the removal of sanctions while ensuring their non-reinstatement in the future.

Global Oil Market in 2024: Uncertainty and Volatility 

Fereydoun Barkeshli

Energy Market Analyst

The global oil market is a dynamic and complex arena influenced by various factors such as geopolitical tensions, technological advancements, environmental concerns, and shifting consumer preferences. Consumer preferences are however influenced by a range of factors mostly influenced via energy transition. Different stakeholders often make vigilant decisions based on market fundamentals and profit considerations. However, the year behind us was exceptionally unique in that most stakeholders including banks and financial institutions, oil analysts, hedge fund managers, and powerful institutions including the International Energy Agency, moved in the wrong direction and changed course throughout 2024. As such it is essential to explore the current landscape of the global oil market, anticipated trends, and the challenges which lie in the structure of oil markets in 2024.                  

Interplay of Tensions

The global oil markets in 2024 were characterized by a complex interplay of geopolitical tensions, economic uncertainty, technological advancements, and shifting energy policies and patterns. The oil demand witnessed a resurgence after a period of sluggish growth. The present note is aimed to discuss various factors influencing the oil markets in 2024. However, the market behavior in 2024 was influenced by various factors that were accumulated and built up since the beginning of the year 2020. The year 2024 was an exceptional year for the market as it experienced the highest rate of demand since the Pandemic. During the first three quarters of 2024, global oil markets registered an additional demand growth of 1.43 mb/d. Such a rate of demand growth has not been seen since the 2020 oil demand collapse. At the time of writing this note, we have not yet seen a confirmed and reliable figure for demand growth for the 4Q2024. However, it is estimated that in the last quarter of the year, demand growth figures surpassed expectations and will probably finish the year with an additional 150 tb/d. 2024 is considered a significant year for the international oil industry in that for the first time in history, emerging economies consumed more oil than the industrialized countries. This is due to the higher rates of industrialization, transportation, and enhanced demographic patterns in countries such as India, ASEAN, and Latin America countries. 

Energy Transition

The term “energy transition” refers to the global shift from one source of energy to the other. The type of energy has been transformed over the years. During the early 1980s, the United Nations took a vigorous position toward energy and rebranded “energy transformation” to “energy transition”. However, the 2015 Paris Agreement further solidified the energy transition by linking it to the carbon emissions phase-out. As such 2015 Paris Agreement established a significant milestone in international climate negotiations, setting ambitious targets for mitigating GHG emissions and curbing global warming. This set the goal and defined commitments by the UN member countries to curb GHG emissions as a fundamental development goal. As such geothermal energy is being prioritized as an alternative to traditional energy.

Global Energy Mix

Oil has historically played a dominant role in the world energy mix. Oil has served as a primary source of energy for transportation, industry, and electricity generation. Britain fought and won two world wars thanks to oil as fluid fuel against its enemies who still fought using solid fuel namely coal. However, now that oil served the purpose, they opted to move away from oil to other sources of energy which are not available to most of the emerging economies in the world today.

When countries voted to reduce oil consumption aggressively in the 2015 Paris COP, there was hardly any meaningful voice from oil producers and less developed countries. Paris Climate Accord took carbon dioxide emissions into its own hands and ignored the rest of the world. OECD took advice and direction from the IEA and ignored other well-established and reputable institutions including the OPEC. The International Energy Agency was so emboldened by the Western-dominated COP agenda that went as far as eliminating all forms of fossil fuels by 2040. This agenda was unanimously approved at a time when OECD members consumed over 60 percent of the world’s coal production which is far more polluting than oil and gas. 

Carbon Emissions Issues

Undoubtedly, climate change issues have been politicized for certain concerned groups and possibly with or even without the intention of governments. The release of sudden and overwhelming evidence and documents on a catastrophic vision of global warming seems manipulated and framed. Having a glance at the political landscape in Europe where climate change models were first reported and presented, one might notice a simultaneous surge of certain political parties that advocated climate action views and serious frictions with the existing political and geopolitical landscapes. 

Scientific facts and evidence were employed to advocate climate change as a threshold for the emergence of a new era of human civilization. It is said that climate activists are financially supported by political lobbyists. Messaging about climate change is not in line with scientific methods of advocating certain factual evidence. The way climate change is discussed in the media and political circles may sometimes overshadow other important issues, leading to the assessment which is being used as a tool for political leverage rather than a genuine environmental concern. 

It is crystal clear for scientists and energy stakeholders that oil is cleaner than coal and gas is cleaner than oil. Scientists have unanimously approved the fact. As such gas is a bridge from oil to renewable sources of energy. This leads to the fact that a meaningful change in energy transition is energy-inclusive. The world economy did not jump from wood to coal and from coal to oil and gas. As such the framing of the climate change issue sounds pretty politicized and contradictory to scientific evidence.

COP29 in Baku: A Turning Point 

The 29th Conference of Parties was held in November 2024. The event was not well received by the mainstream media as was expected. However, it could be regarded as one of the most important energy-related events of the year behind us. 

COP29 was held in a country with not much of resources other than oil. COP28 was also held in the United Arab Emirates, a country known for its oil. Two consecutive climate change conferences in oil-producing countries had a

message. This is an indication that the OECD members have realized that they have to differentiate between facts and fiction, and between climate realities and climate activism. It is also a powerful message that the oil-producing countries intend to place the climate change issue where it can be heard well. In the meantime, the 30th COP will be held in Brazil, a country that intends to join the oil-producing Club of Nations and a member of BRICS. 

The reason why I intended to bring up the issue of COPs and COP29, in particular, is that, unlike the previous COP, several world leaders refrained from attending the conference almost entirely due to the geopolitical situation around the world. In fact, it was one of the rare COP meetings where leaders had more important things to attend than the Climate Change Conference. Other priorities diverted focus from the imperative to act on climate change.

This dynamic was on the show at COP29 in Baku. In the meantime, the coalition of oil producers was all in attendance. The coalition of oil-producing nations virtually blocked any mention of phasing out fossil fuels in the final agreement. In many ways, the oil-producing countries joined forces with the emerging world to voice their opposition to phasing out fossil fuels in a manner that is convenient for the Western Hemisphere. Climate change is a global problem and it requires global wisdom and cooperation.

It is noteworthy that in COP29 sessions something still more interesting emerged: climate change is itself beginning to impact geopolitics. This is like a vicious circle. Climate change is making geopolitics less stable, which harms climate actions. This will worsen climate change, meaning more geopolitical instability and so on. The risk is that the circle runs faster and ultimately derail the ability to phase out fossil fuels fast enough to avoid the climate consequences.

US Presidential Election Results

The US presidential results are considered a threshold for the United Nations Framework  Convention on Climate Change conferences.

Eight years ago when the Trump administration was stationed in the White House, the American delegation wandered around aimlessly in Morocco during COP22 shocked and confused about what they must do. Trump was preparing for the process of leaving the Paris Climate Agreement and his administration was perplexed about the issue of climate diplomacy. In fact, Trump got the entire Texas vote under the pretext that he would promote more drilling, more shale, and America’s self-sufficiency in energy production and consumption.

Macro factors play a much more important role this time. There is hardly anything more that Trump can do to curb the force of climate change activists and promote oil production. President Biden has been more Trumping than Trump himself. Biden promoted oil production LNG production and exports in a way that no other president has been able to do. 

US shale oil production is already aging. Trump’s energy policies cannot pump more oil than has already been tapped. This time, the new administration must tackle the massive US debt problems, inflation which is temporarily stable for now but can shoot higher soon. In the meantime, interestingly climate can play its role as a factor driving inflation.

The issue of energy transition is highly politicized and divides the OECD from the emerging economies. 

Factors in 2025

While discussing the oil market fundamentals in 2025, all eyes

are focused on the supply side. This certainly has relevance but several macro factors are deeply intertwined in the market direction. In continuation, I would like to shed more light on some important issues.

Europe and China enjoyed cozy trade and economic ties for some twenty years. The United States was into it as well, though somewhat differently.

European Union imported relatively cheap and abundant energy from Russia. China posed as the world factory and produced parts and equipment for Europe and to some extent the US. Major European countries, mostly Germany and France manufactured and exported huge quantities of machinery and finished products to China.

So far so good. All were happy and the EU was the happiest. European vehicles were on the roads in the streets of Shanghai and Beijing. In the meantime, oil producers were among the most beneficiaries. At some point in time, China imported some 14.4 mb/d of oil mostly from Middle Eastern countries. The war in Ukraine changed many parameters fast. Faster than expected. 

The flow of Russia’s piped natural gas into Europe was disrupted. The volume of gas supplied to most of Europe was squeezed. The US Shale gas production was increased by four times in one year. The US captured EU gas markets by sending huge volumes of gas in the form of LNG to Europe. Though the price that the Europeans paid was four times higher. In the meantime, China introduced its Plan B economic model. China changed course from an export-oriented to an inward-looking economy. In the meantime, China surfaced lots of hidden Artificial Intelligence technologies. China is rich in rare mineral resources and in the meantime has invested heavily in Africa and Latin America for rare earth resources. China has virtually overcome the obstacles related to batteries that are essential for making modern-day technology. Today four out of five cars that are manufactured in China are Electric Vehicles (EV). In Europe, it is the vice versa. Only one out of every four cars manufactured in Europe is EV. Chinese cars are capturing European markets in a big way. 

Historic Transition

One of the major factors that influence the global oil market is related to a historic transition characterized by turmoil and economic transformation in the Middle East. The region is moving away from a geopolitically important region towards geoeconomics. It is interesting to note that China is positioned to play a major role in the new Middle Eastern configurations. The region is gaining significance in the way that China is vigorously supporting it as a substitute for Europe. It is commonly argued that Europe and the Euro will continue to weaken and will not be a strong player in the world economy. China is vigorously trying to replace Persian Gulf economies with that of the Eurozone.

Such convergence will accelerate changes in the region and will shape the future regional landscape across the Middle East. It is also evident that the Middle Eastern countries are actively attempting to join the BRICS and Asian regional integration. This trend is already evident from closer relationships between Iran and other major economies in the region with that of China. The Middle East has emerged as a key destination for China’s new energy companies, providing vast development opportunities despite increased global trade challenges. The Middle East offers significant advantages due to its abundant solar and wind resources.

The Asian century has arrived and is here to stay.

The biggest oil producers and consumers of the world oil are Asians. It is for Asia to decide the future of the oil industry. I believe that 2025 will be a crucial year for the Global South.

US Bigger Role in Europe Energy Supply

Shuaib Bahman

The Nord Stream 2 pipeline was designed to transmit natural gas directly from Russia to Germany, cutting through the Baltics. It is now amid geopolitical tensions between the US and Europe. The United States’ fresh sanctions on the pipeline are indicative of a wider strategy aimed at undermining Russia’s energy dominance in Europe, particularly following its attackon Ukraine.Therefore, studying the impact of renewed sanctions on Russian gas exports to European markets in 2024 would be important.

Fresh Sanctions on Nord Stream 2

Liquefied natural gas (LNG) is too important to be ignored in Europe. In the aftermath of the energy crisis caused by Russia’s invasion of Ukraine, European countries quickly realized that their dependence on Russian gas was a significant vulnerability. Meanwhile, US sanctions targeting the Nord Stream 2 project significantly increased following Russia’s military actions in Ukraine. In December 2019, the US Congress adopted Protecting Europe’s Energy Security Act (PEESA) to punish companies involved in the construction of the Nord Stream 2 project. These sanctions were mainly aimed at weakening Russia’s capacity to skirt around traditional transit routes, particularly via Ukraine, thereby bolstering European energy security while weakening Russia’s bargaining power.

After the outbreak of the war on Ukraine in February 2022, the Biden Administration adopted a more aggressive position against the pipeline. He blocked certification for the project, laying the blame on Russian military activities. Subsequent legal action led to broader sanctions that targeted not only pipeline operators but also shipping companies, insurance providers, and other entities associated with the project.

In 2024, the sanctions regime expanded to include fresh punishment for Russian entities involved in the energy sector, including the Nord Stream 2 project, and maritime transport bodies. The sanctions were aimed at creating a more comprehensive obstacle in the way of Russian energy exports and were indicative of current geopolitics as Western governments were seeking Russian economic isolation.

Fallout for Russian Gas Exports to Europe

The tightening of US sanctions on the Nord Stream 2 pipeline had an immediate and significant impact on Russian gas exports to Europe. The sanctions not only halted the pipeline’s operation but also contributed to an overall reduction in Russian gas supplies to European countries. By 2024, data shows that Russian gas exports to Europe will have fallen by more than 55% from pre-attack levels, reflecting the cumulative effects of ongoing sanctions and Russia’s escalating military operations in Ukraine.

The Nord Stream 1 and 2 pipelines, which were expected to double Europe’s gas supply, were largely rendered unusable after incidents in 2022 that damagedvital infrastructure. As a result, European countries faced severe gas shortages, with governments looking for alternative sources of supply and trying to secure liquidity through increased imports of LNG from the US and other global suppliers.

In response to these developments, the EU took aggressive steps to reduce its dependence on Russian energy, including efforts to diversify suppliers and increase investment in renewables. The EU’s share of gas imports from Russia fell from around 40% in early 2021 to around 15% by late 2023, a trend that significantly changed the continent’s energy outlook.

US Gas Exports Rise

The most important aspect of America’s contribution to Europe’s energy supply is the country’s dramatic increase in LNG exports. After the tightening of sanctions on the Nord Stream 2 pipeline, US liquefied natural gas exports to Europe increased sharply, making the US a major energy supplier. In 2022, US LNG exports to Europe exceeded 75 bcm, up 137% year-on-year.

By 2024, the US supplied more than 50 percent of Europe’s total LNG imports, a shift that fundamentally transformed the way Europe supplied energy. This shift was facilitated by the development of a vast network of LNG terminals and regasification facilities in Europe, built to accommodate the increased imports.

Moreover, the geopolitical importance of the US’s role in supplying Europe with energy signals a shift in global energy politics. A shift towards US LNG would fundamentally alter the balance of energy relations, reducing Europe’s previous dependence on Russian gas and potentially reshaping energy supply chains on a global scale.

Long-Term Fallout and Future Perspective

The US’s tougher sanctions on the Nord Stream 2 pipeline have had profound implications for Russian gas exports to Europe. The long-term implications of the tightening of US sanctions on the Nord Stream 2 pipeline and its impact on Russian gas exports to Europe are therefore multifaceted. Faced with the loss of Russian gas supplies, countries are significantly investing in renewable energy infrastructure and alternative gas sources, which is changing the energy security paradigm in Europe.

Reducing dependence on Russian gas will not only have a detrimental impact on Russia’s revenues – which are expected to be severely affected by sanctions – but may also change the geopolitical landscape in the future. As Europe becomes more energy independent, it may reduce Russia’s influence and bargaining power over its neighbors, especially Eastern European countries that were previously heavily dependent on Russian energy imports. Increasing energy diversification, coupled with strong policies promoting renewable energy, is therefore likely to continue as a strategic priority among European countries.

Mideast Impact on the Energy Market

Shuaib Bahman

The Middle East’s geopolitical outlook has significantly impacted global energy developments due to the crucial role of the region in oil and gas production.In 2024, some events transformed the situation in the region, leaving significant impacts on the energy market and giving rise to consequences on oil prices, security of supply, and energy transit initiatives. Therefore, it is important to analyze these impacts and realize how geopolitical tensions have transformed market equations and supervisory reactions in the energy sector.

Geopolitical Tensions and Energy Management

Against the background of the Zionist regime-Hamas conflict, oil prices experienced fluctuations that alerted market participants. While oil prices initially rose to above $80 a barrel after the escalation of tensions in October 2023, they did not remain at that level. At that time, instability in the Middle East caused tough conditions for oil traders and consumers mainly feared disruptions in energy supply. It is noteworthy that the Middle East has historically been instrumental in oil supply chains and currently accounts for about one-third of the global oil supply. As tensions were stoked, concerns grew about possible military action against Iran’s oil facilities and the Strait of Hormuz, which is a key point for world oil transit. Had any major disruptions hit the region, consequences would be tough for energy markets and oil prices were likely to rise significantly.

Oil Price Stability Despite Tensions

Oil supply by non-OPEC nations like the United States, Brazil, and Guyana helped stabilize the market.
Estimates was an indication of OPEC+’s growing spare capacity, particularly among Persian Gulf producers, which eased immediate concerns about supply restrictions.
The market players realized that ongoing conflicts in the Middle East, albeit hazardous, do not threaten vital production infrastructure.
The fragile conditions in the Middle East brought about a bigger change to energy dynamism as top oil consumers looked for alternative sources of energy in a bid to reduce their dependence on fossil fuels.

In response to oil price fluctuations, many governments have launched strategies to boost investment in renewable energy and improve energy efficiency. For example, investments in clean energy technologies increased significantly in 2024, reflecting a dual response to immediate market pressures and long-term sustainability goals. That represented a critical shift in energy transition policies.

Energy Policy and Investment Changes

Conflicts in the Middle East have given new impetus to discussions about diversifying energy supplies and investing in clean technologies. With global investment in clean energy projected to exceed $3 trillion by 2024, trends suggest that policymakers have recognized the need to create a resilient and sustainable energy framework in light of ongoing geopolitical risks.Countries facing immediate economic pressures, such as inflation from oil price fluctuations, emphasized the importance of diversifying energy sources and accelerating the transition to renewable energy sources to reduce future vulnerabilities to global oil shocks.

In addition, significant investments have flowed into renewable energy projects, driven by new policy initiatives in various countries. Increased government support for clean technologies reflects efforts to foster energy independence against a backdrop of instability in the Middle East. This shift not only serves the immediate goals of economic recovery but also represents a long-term strategic vision to reduce dependence on oil imports from unstable regions.

Conclusion

Events in the Middle East in 2024 once again pushed to bold relief the complex link between geopolitical developments and global energy markets. The resulting volatility in oil prices, coupled with growing concerns about energy security, demonstrated the far-reaching consequences of regional conflicts on the global stage.As oil prices rose after the conflict began, driven by concerns about a broader military escalation, countries realized that the heavy dependence on fossil fuels imported from the Middle East posed significant risks to economic stability and energy security. In response, many countries began to push for investment in renewable energy infrastructure, signaling a strategic shift toward sustainability and energy independence.

Despite the measures in place, oil prices are likely to continue to be subject to significant volatility if the conflict in the Middle East continues. For example, if more players become involved or the war spreads or becomes a wider regional quagmire, then prices could reach levels not seen since the 1970s. For example, scenarios that predict a full-blown war with Iran could push oil prices to $150 per barrel.

The long-term consequences of the conflicts in the Middle East therefore remain uncertain and depend on the evolution of the conflict and the broader geopolitical landscape of the Middle East. As countries navigate this complex environment, the interaction between politics and global oil prices will continue to be an important factor in shaping energy policy and market strategies.

1- Mexico Gas Line Facilities Finished

According to a Jan. 7 company news release, Allseas has finished all work on the 700-km, 36-inch Southeast Gateway pipeline project offshore southeast Mexico for TC Energy.

The company mobilized multiple pipelay barges, and onshore and offshore teams for the 11-month campaign, including the nearshore scope and pre-commissioning of the entire system. TC Energy initially contracted Allseas to install the offshore pipeline in October 2022.

The Solitaire vessel laid most of the pipeline, which Lorelay and Tog Mor supported. The Pioneering Spirit vessel installed the remaining nearshore section at Coatzacoalcos. Instead of a stinger, the vessel’s hanging stinger transition frame served as a "mini' stinger to suit laying in the shallow-water depth.

2-Norway Reviews Installations Electrification

Multiconsult Norge, Aker Solutions, and LINK Arkitektur will jointly perform engineering services for Equinor's electrification of multiple oil and gas installations offshore Norway.

These are located in the Halten, Tampen, and Grane Balder areas of the Norwegian Sea and North Sea.

The pre-FEED/FEED contract also contains options for detailed engineering, follow-on work, procurement assistance, and construction supervision, with a potential value of $52.64 million.

All work is due to be completed by 2030.

Activities include engineering the associated onshore grid connections, transmission lines, onshore cabling, three substations, and landfalls.

3-Petronas Plans Platform Complex in Indonesia

Petronas subsidiary PC North Madura II has committed to develop the Hidayah oil field in the North Madura II contract area offshore East Java, Indonesia.

The plan calls for an unmanned integrated wellhead and central processing platform, and a floating storage and offloading (FSO) unit with living quarters and a central control room.

Offshore Peninsular Malaysia, BeicipFranlab Asia is collaborating with Petronas, via Malaysia Petroleum Management (MPM), on a new study to explore unharnessed energy resources in the Malay basin.

The project employs 4D modeling and machine learning to analyze the subsurface at both basin and reservoir scales. Another focus is on predicting hydrocarbon migration and entrapment by drawing on available data from the Malay basin, which has produced more than 9 Bboe since the 1970s.

4-Africa Oil Raises Stake in South Africa Block

Africa Oil has raised its direct interest in Block 3B/4B in the Orange Basin offshore South Africa to 18%, following a transaction with Eco (Atlantic) Oil & Gas.

The block is southeast of and on-trend with various discoveries including Venus, and it is operated by TotalEnergies. It covers a 17,581-sq-km area in water depths ranging from 300-2,500 m.

Eco subsidiary Azinam has transferred a 1% stake in the block to Africa Oil, which in return has exchanged the shares and warrants it held in Eco for cancellation.

Existing data coverage comprises about 14,000 km of 2D seismic and 10,800 sq km of 3D seismic, with most of the identified prospects in about 1,500 m of water.

5-Asset Swap Offshore Australia

Woodside Energy and Chevron have agreed to an asset swap covering multiple development projects offshore Western Australia.

Under the proposed transaction, Woodside will acquire Chevron’s 16.67% interests in the North West Shelf (NWS) project, the NWS oil project, and Chevron’s 20% stake in the Angel Carbon Capture and Storage (CCS) project. Chevron would also make a cash payment to Woodside of up to $400 million.

In exchange, Chevron would receive Woodside’s 13% share in the offshore Wheatstone development and Woodside’s 65% operated interest in the Julimar-Brunello project.

Fulfillment of the deal is subject to completion of the Julimar Phase 3 execution and handover, anticipated in 2026, and of various ongoing abandonment programs.

Talos Energy Eyes Commercial Oil/Gas in the Gulf of Mexico

Talos Energy has proven commercial volumes of oil and gas with its Katmai West #2 appraisal well in the Ewing Bank area of the US Gulf of Mexico.

The West Vela drillship spud the well in late October 2024. Going forward, the plan is to case and suspend the well by late January while Talos finalizes completion plans, which it aims to execute during the second quarter.

Katmai West #2 will be connected to the subsea infrastructure serving the Tarantula production platform, where capacity has been expanded to accommodate up to 35,000 boe/d.

Talos expects both Katmai West wells to produce on a rate-constrained basis, enabling extended flat-to-low decline production.

The company has a 100% operated interest in Tarantula and a 50% operated share of Katmai West, the remainder held by entities managed by Ridgewood Energy.

John Spath, Talos' interim co-president, EVP, and head of operations, said the high-impact deepwater well was drilled about 35% under budget and over a month ahead of schedule.

He added, “We remain optimistic about the greater Katmai area, as these results align with our pre-drill expectations.”

Katmai West #2 well was drilled to a TVD of about 27,000 ft after encountering the main target sand full-to-base, with more than 400 ft of gross hydrocarbon pay. During production, the well should deliver 15,000 to 20,000 boe/d.

Results from both wells have led to the ultimate recovery of the Katmai West field being almost doubled to about 50 MMboe. Talos sees an overall resource potential of close to 100 MMboe gross.

The first production is expected in the late 2Q 2025.

Prime Agrees to Join Tower in Thali Drilling

Tower Resources has conducted farm-out agreements with Prime Global Energies covering exploration projects offshore Cameroon and Namibia.

Pending approvals, Prime will take a 42.5% non-operated interest in the Thali license offshore Cameroon by contributing $15 million to the ongoing work program and drilling of the NJOM-3 appraisal well later this year.

In addition, Prime will farm into 25% of the PEL96 offshore Namibia. Tower hopes to finalize both arrangements by the end of March.

Prime is a UK-incorporated upstream operation. Parent company Prime International Oil and Gas acquired Eni’s E&P interests in Pakistan.

The two parties have in principle also agreed to work together on other projects in Cameroon.

Tower aims to use part of the proceeds to fund its activities offshore Namibia, including the evaluation of large stratigraphic and structural leads and prospects across the license area.

It aims to reprocess prior 2D seismic that was acquired over large parts of the license to build a more detailed picture of prospective structures. That work will support the selection of a 3D seismic data acquisition area.

Shell Starts Production at Whale

Shell Offshore Inc. reports that production has started at the Shell-operated Whale floating production facility in the Gulf of Mexico. 

The Whale production facility is in the Alaminos Canyon Block 773 and is adjacent to the Shell-operated Silvertip field, about 10 miles (16 km) from the Shell-operated Perdido platform and about 200 miles (320 km) south of Houston.

Discovered in 2017, the Whale field features a semisubmersible production host in more than 8,600 ft (2,600 m) of water with a total of 15 wells to be tied back to the host via subsea infrastructure.

Shell says the Whale facility replicates the simplified, cost-efficient host design of the Vito platform, a four-column semisubmersible host facility that began production in early 2023.

With an estimated peak production of 100,000 barrels of oil equivalent per day (boe/d), Whale currently has an estimated recoverable resource volume of 480 MMboe. Whale replicates 99% of the hull design and 80% of the topsides from Vito.

Shell says the Whale facility also features energy-efficient gas turbines and compression systems, operating with about 30% lower GHG intensity over its life cycle than Vito.

The Whale development is owned by Shell Offshore Inc. (60%, operator) and Chevron U.S.A. Inc. (40%).

Argentina Negotiating Gas Imports

Bolivia and Chile are in talks to resume gas exports to Argentina amid a surge in demand spurred by a summer heat wave, underscoring the challenge for the government in Buenos Aires as it looks to become energy self-sufficient.

"We are in a negotiation with Argentina to create a spot contract," the chief of Bolivia’s state-run energy firm YPFB, Armin Dorgathen Tapia, told Reuters by phone. The talks are previously unreported.

Chilean authorities also said in a statement to Reuters that they expect to reach a new agreement with Argentina to supply the country's remote north. Up to 2.5 million cubic meters of natural gas could be shipped per day through September, the energy ministry said.

Natural gas exports from Bolivia to Argentina ended in September after almost two decades, as Argentina ramped up domestic production from its huge Vaca Muerta shale formation and started shifting towards becoming a net energy exporter.

Bolivia’s gas production has also been dwindling over the last decade with few discoveries. Since last year, Yacimientos Petroliferos Fiscales Bolivianos (YPFB) no longer has an active supply contract with Argentina.

But extreme heat that struck Buenos Aires and the surrounding regions this week has led to an uptick in energy demand, as Argentines crank up air conditioners and fans, putting pressure on domestic supplies.

Argentina's state energy firm Enarsa confirmed to Reuters that it was "open to alternatives" should the country need to import gas to meet demand. Argentina is not currently importing gas from its neighbors, the firm said.

Bolivia can send gas to Argentina as part of a potential new short-term spot contract lasting between six and 12 months, the YPFB president said.

Bolivia's gas supplies are already committed to neighboring Brazil as part of a recent deal through to 2027 but some clients "don't demand as much, so we can be flexible," he said.

YPFB added that Bolivia could even generate electricity of its own to sell back to Argentina."There are solutions," Tapia added.

YPFB cautioned, however, that an outstanding debt due to the firm from Argentina complicated future transactions. Argentina was due to make a payment on Jan. 10 totaling $10.6 million for supplies received, according to YPFB, but had not done so.

"It is difficult for us to have the confidence to be able to send gas to Argentina, knowing that they may not pay," Tapia said.

A spokesperson for Argentina's Enarsa said there was no debt outstanding with YPFB, but rather a discrepancy over the amount of gas Bolivia provided during the contract period. Talks to resolve that are due to continue next week, the person added.

Argentina’s energy ministry did not immediately respond to a Reuters request for comment.

The country, South America’s No. 2 economy, has been rapidly ramping up gas output and is making multi-billion-dollar investments in pipelines and longer-term plans for liquefied natural gas (LNG) terminals to allow gas shipments overseas.

SLB Russia Business Aligns with US Sanctions

Oilfield service provider SLB said its current business in Russia still aligns with U.S. sanctions issued this month, but that revenue in the country was declining.

The world’s largest oilfield service company is one of the few Western firms to remain in Russia after its 2022 invasion of Ukraine.

SLB is under pressure to leave Russia after the U.S. Treasury Department on Jan. 10 issued new sanctions that included adjusting an executive order to cut off Russia's access to U.S. services related to the extraction and production of crude oil and other petroleum products. Companies have until Feb. 27 to wind down operations, according to the sanctions.

U.S. lawmakers from both political parties had urged the Treasury to close the loophole allowing SLB to operate in Russia, which they say boosts revenues for Russian President Vladimir Putin’s war on Ukraine.

"Any reasonable interpretation of Treasury’s new guidance that ‘cuts off access to U.S. services related to the extraction of crude oil’ would mean getting U.S. oilfield services companies out of Russia," said U.S. Representative Lloyd Doggett, a Democrat.

President-elect Donald Trump’s policy on Russian sanctions is uncertain. President Joe Biden's sanctions were intended to help Trump get a deal in Ukraine.

SLB is reviewing the new sanctions and believes that voluntary measures it has taken to curtail its Russian activity, including halting shipments of product and technology into the country from all SLB facilities worldwide, are aligned with the new restrictions, Chief Executive Officer Olivier Le Peuch said in an earnings call.

SLB raised its quarterly dividend and accelerated share repurchases as its 4Q profit beat expectations, while also warning of flat 2025 revenue due to an oil oversupply.

Revenue from SLB’s operations in Russia has been declining and accounted for 4% of its total revenue in 2024, down from 5% the year before, he said.

Equinor Secures $3bn Financing for Wind Project

Norway’s Equinor said it had secured a financing package of more than $3 billion for its Empire Wind 1 offshore wind power project in the United States.

The company expects the total capital investments, including fees for the use of the South Brooklyn Marine Terminal, to be around $5 billion, including the effect of future tax credits, it said in a statement.

Equinor intends to farm down in the Empire Wind 1 project to a new partner to further enhance value and reduce exposure, it added.

Empire Wind 1 will power 500,000 New York homes and is expected to reach its commercial operation date in 2027, according to Equinor.

Equinor must respond to an investigation conducted by the Norwegian Ocean Industry Authority (Havtil) into an incident onboard the Åsgard A production vessel in the Norwegian Sea last January.

During a heavy storm, a large wave (green water) struck the platform. The pressure from the wave exceeded the load resistance of one cabin window, leading to both the window and window frame being forced into the cabin.

There was damage to the inside and outside of the cabin, with large volumes of seawater surging into the living quarters. Had staff been present in the cabin, there could have been a serious injury or fatality.

The investigation has identified the following underlying causes: the location of the emergency escape shaft; design and execution of the window fixing; lack of protection for cabin windows; insufficient green water model tests; and follow-up of observations.

Non-conformities identified included inadequate assessments for green water; a lack of compliance with internal requirements for covering cabin windows; and weakened load resistance of cabin windows.

Another factor was also observed that has been categorized as an improvement point. This concerned wave measurements and meteorological observations.

Havtil has asked Equinor to identify measures and draw up a plan for implementing these by February 2028.

Valeura Outlines Thailand Drilling Goals

Valeura Energy has budgeted 2025 CAPEX in the range of $125 million to 150 million for its global E&P programs, plus about $11 million for exploration drilling.

Close to 85% of the expenditure will be directed toward drilling, with one drilling rig on contract offshore Thailand throughout the year. The remainingCAPEX will be allocated to brownfield developments in the region.

In an operations update, the company noted that the Nong Yao field in license G11/48 in the Gulf of Thailand is now its largest producer, accounting for about 40% of its anticipated production this year.

Valeura plans to drill 11 development and appraisal wells here, including new targets drilled from the producing Nong Yao A, B, and C facilities.

The wells should lead to a more thorough sweep of incremental oil from producing reservoirs, and it will also access fault blocks and reservoir layers not currently penetrated by the existing producer wells.

Following last year’s discovery in the Nong Yao D area, new seismic interpretation has identified further exploration opportunities in the area, which could be included in a future drilling campaign. The company aims to prove sufficient volumes for future development.

On license B5/27, containing the Jasmine field, this year’s line-up comprises 13 new development and appraisal wells from the Jasmine C and D and Ban Yen production facilities. The primary goal will be to drill new horizontal laterals into producing reservoirs to optimize the sweep of oil and prove fresh reserves.

Around the end of the first quarter, the company expects to commission a low BTU gas generator, which will redirect a waste gas stream for use in power generation. This should reduce Jasmine’s emissions intensity and its reliance on diesel-fired power generation.

Another exploration prospect under review is Ratree, which is to the south on license B5/27.  Success here could unlock the path toward a new field development.

At the Manora field in license G1/48 (Valeura 70%), production should rise following the completion of a current five-well infill drilling program, including development and appraisal targets.

Although no new drilling activity is planned this year on the Wassana field in license G10/48, FEED studies continue for a potential redevelopment to commercialize oil volumes discovered through appraisal and exploration drilling in 2023 and 2024. FID approval readiness should occur early in the third quarter.

Delayed Energy Transition and Upstream Sector

As the risk of a “delayed energy transition scenario” increases, so does the possibility of a much greater pull on future oil and gas supply, says global consulting firm Wood Mackenzie.  

The firm defines a “delayed transition scenario” as a five-year delay to global decarbonization efforts due to “ongoing geopolitical barriers, reduced policy support for new technologies, and cost headwinds.”

However meeting this future hydrocarbon demand would require a significant increase in upstream investment, resulting in higher hydrocarbon prices and significant shifts in corporate strategy, according to Wood Mackenzie’s latest Horizons report.

According to the report “Taking the strain: how upstream could meet the demands of a delayed energy transition,” a variety of external pressures have weakened government and corporate resolve to spend the estimated US $3.5 trillion required to restructure energy systems to limit both hydrocarbon demand and global warming.

Wood Mackenzie’s latest Horizons report focuses on the additional resources and spending required if the upstream sector were to meet higher-for-longer oil and gas demand and the resultant consequences.

Under this scenario, the world would require 5% more oil and gas supply and 30% higher annual upstream capital investment. Liquid demand would average 6 million b/d (6%) higher than Wood Mackenzie’s base case to 2050, and gas demand would average 15 bcfd (3%) higher than the base case.

“Meeting rising demand in the near term in either the delayed scenario or the base case poses little challenge to the sector; plenty of supply is available,” said Fraser McKay, head of upstream analysis for Wood Mackenzie.

“However, stronger-for-longer demand growth is a much stiffer ask. A five-year transition delay would require incremental volumes equivalent to a new US Permian basin for oil and a Haynesville Shale or Australia for gas,” said Angus Rodger, head of upstream analysis for Asia-Pacific and the Middle East.

Australia Approves North West Shelf Plan

The Western Australian Government has issued environmental approval for theNorth West Shelf ProjectExtension offshore/onshore North West Australia.

According to operator Woodside Energy, it follows a six-year process of assessment and appeals.

The state’s decision allowedthe recommencement of the federal environmental approvals process, which was put on hold while the appeals were considered.

Liz Westcott, Woodside Executive Vice President, and COO Australia, said the state’s decision represented an important step to secure long-term processing of North West Shelf Joint Venture offshore field resources and third-party gas resources through the onshore Karratha gas plant.

This year marks 40 years of domestic gas production through Karratha and 35 years of LNG exports.

As part of the approval, the joint venture partners committed to various environmental management measures, including a reduction in air emissions such as oxides of nitrogen and volatile organic compounds and other measures to reduce greenhouse gas emissions over time.

The Danish Energy Agency (DEA) is inviting bids to explore certain nearshore areas of Denmark for subsurface storage of CO2.

This fourth tender round of permits covers the Jammerbugt, Lisa, and Inez areas. Applications must be submitted by March 6, 2025.

Previously, the Minister for Climate, Energy and Utilities issued three offshore CO2 exploration permits in February 2023. 

The permit process comprises an exploration phase and a storage phase. The exploration period, lasting up to six years, calls for investigations to assess whether subsurface conditions are suited to safe storage of CO2, and the extent of the storage capacity.

A subsequently awarded storage permit could apply for up to 30 years with the potential for a further extension. About 20 years after the closure of the storage facilities, the area would be returned to the state.

Jammerbugt, Lisa and Inez are among the areas singled out by the Geological Survey of Denmark and Greenland (GEUS) because the geological conditions appear to be particularly suitable for storing CO2 in the subsurface.

BP Outlines Drilling Goals Offshore Azerbaijan

BP issued its 3Q 2024 results on Nov. 5, providing a progress report on ongoing development works at the Shah Deniz and ACG fields in the Azerbaijani sector of the Caspian Sea.

During the 3Q, preparations continued for the commissioning of a third gas production well at Shah Deniz 2 on the field’s East North flank.

Activities performed by the Istiglal and Heydar Aliyev rigs included the de-completion and re-completion of the SDH02 well on the East North flank and the de-completion of the SDF02 well on the West South flank. Heydar Aliyev was also drilling the SDD05 well on the West flank.

To date, 21 wells have been drilled for Shah Deniz 2, comprising five on the North flank, four on the West flank, four on the East South flank, five on the West South flank, and three on the East North flank.

BP has continued to analyze data obtained last year from the target reservoirs of the SDX-8 exploration well, the aim being to appraise the deeper reservoirs beneath the currently producing Shah Deniz layers.

At the ACE platform, the current production of about 19,000 bbl/d from two wells should rise to 24,000 bbl/d once the next planned well is drilled, completed, and brought online. During the first three quarters of the year, the ACG teams completed 11 oil producers, two water injectors, and one cutting re-injection wells.

During September, SOCAR, BP, and the other ACG co-venturers signed an addendum to the existing ACG production sharing agreement, pledging to pursue exploration, appraisal, development of, and production from the field’s NAG reservoirs. These could hold up to 4 tcf in place.

An initial well is being drilled from the West Chirag platform to produce gas from two priority reservoirs. It will also provide appraisal feedback to support future development planning.