Azeri Central East joins six other offshore platforms that were already installed on the ACG field, which has been producing since 1997. To date, the offshore Azerbaijani field, located off the coast of Baku, has yielded more than 4.3 billion barrels of oil.

The development of the ACE project was approved in April 2019. It is the first platform to come online since the start-up of the West Chirag platform in 2014.

BP operates two more platforms in the Caspian Sea, which serve the Shah Deniz gas field.

The ACE platform and its associated facilities are engineered to handle a capacity of up to 100,000 barrels of oil per day (bpd), with the project anticipated to yield approximately 300 million barrels throughout its operational lifespan.

The 48-slot production, drilling and quarters platform sits midway between the Central Azeri and East Azeri platforms in a water depth of 137m.

Its jacket has a weight of 16,000 tonnes and a height of 153m. The platform houses three production risers, one for water injection, one for oil export, and one for gas export.

BP projects senior vice president Ewan Drummond said: “I’m incredibly proud of the team at bp for safely delivering the first bp-operated offshore platform fully controlled from onshore. This establishes a new benchmark for innovative engineering and competitive project delivery for our company and the wider industry.”

Oil undergoes processing on the platform before being transported roughly 130km via a newly established in-field pipeline to the Sangachal terminal onshore, connected to an existing 30″ subsea export line.

Initial oil production from ACE is from the first well that was drilled from the platform towards the end of last year.

Production from ACE is projected to ramp up through 2024, to approximately 24,000bpd as two additional planned wells are drilled, completed, and integrated into operations.

BP is the operator of the ACG project with a stake of 30.37%. Its partners include SOCAR (25%), MOL (9.57%), INPEX (9.31%), Equinor (7.27%), ExxonMobil (6.79%), TPAO (5.73%), ITOCHU (3.65%), ONGC Videsh (2.31%).

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The deal mainly involves Equinor transferring its 100% stake and operatorship in Ohio’s Marcellus and Utica shale formations in the Appalachian Basin, situated in southeastern Ohio, to EQT. This will be in return for a non-operational 40% interest from EQT in the Northern Marcellus formation in Pennsylvania.

To balance the transaction, Equinor will provide a cash payment of $500m to EQT.

Equinor said that the asset swap deal is aimed at bolstering resources contributing to increased cash flow and further decreasing the CO2 emissions intensity within the firm’s international portfolio.

After the transaction, the Norwegian energy major will raise its average working interest from 15.7% to 25.7% in specific Northern Marcellus gas units operated by Chesapeake. In order to fulfill prior gas sales obligations, Equinor will engage in a gas buy-back arrangement with EQT.

Equinor exploration and production international executive vice president Philippe Mathieu said: “With this transaction, we continue to high-grade the US portfolio and improve profitability by strengthening our gas position in the most robust part of the Appalachian Basin. These assets are well positioned to leverage anticipated positive developments in the US gas market.

“The proposed swap improves portfolio robustness with an expected reduction in well break-evens and upstream carbon intensity. This also means that we have now fully exited all operated positions onshore US.”

Through the agreement, Equinor will acquire an estimated 225 million cubic feet per day (MMcf/d) of projected 2025 net production from the Northern Marcellus shale formation.

On the other hand, EQT will receive approximately 26,000 net acres in Monroe County, Ohio, with an estimated 2025 net production of 135 million cubic feet equivalent per day (MMcfe/d) directly offsetting its operated acreage.

Additionally, EQT will gain around 10,000 net acres in Lycoming County, Pennsylvania, with a projected 2025 net production of approximately 15MMcfe/d from its existing operated assets.

Furthermore, EQT will obtain the remaining 16.25% ownership in the company-operated gathering systems that serve core operated acreage in Lycoming County, Pennsylvania.

EQT president and CEO Toby Rice said: “This transaction marks an extremely positive start to our divestiture program, bringing in over $1.1bn of value, including synergies and development plan optimisation, for 40% of our non-operated assets, while retaining gas price upside.

“We plan to opportunistically divest the remaining portion of our non-operated assets in Northeast Pennsylvania and have tremendous confidence in being able to achieve our de-leveraging goals.”

Contingent on customary closing adjustments, the mandated regulatory approvals and clearances, the deal is anticipated to close in late Q2 2024.

Last month, EQT signed a deal to acquire Equitrans Midstream in a move to create a major vertically integrated natural gas enterprise in the US, with an initial enterprise value of over $35bn.

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The company made the final investment decision (FID) after receiving the necessary government and regulatory approvals.

The Whiptail project, which will use a Floating Production Storage and Offloading (FPSO) vessel, will entail an investment of around $12.7bn. It would include up to ten drill centres with 48 production and injection wells.

The FPSO vessel, set to be named Jaguar, is currently under construction.

By the end of 2027, the development is expected to increase Stabroek block’s production capacity by around 250,000 barrels per day.

ExxonMobil Upstream Company president Liam Mallon said: “Our sixth multi-billion-dollar project in Guyana will bring the country’s production capacity to approximately 1.3 million barrels per day.

“Our unrivalled success in developing the Guyana resource at industry-leading pace, cost and environmental performance is built on close collaboration with the government of Guyana, as well as our partners, suppliers, and contractors.

“The Stabroek block developments are among the lowest emissions intensity assets in ExxonMobil’s upstream portfolio and will provide the world with additional reliable energy supplies now and for years to come.”

ExxonMobil affiliate ExxonMobil Guyana operates the Stabroek block with 45% interest. The remaining stake is with Hess Guyana Exploration (30%) and CNOOC Petroleum Guyana (25%).

Currently, more than 6,200 Guyanese support Stabroek block operations. The figure represents 70% of the workforce.

The projects in Stabroek block also support economic development for Guyana, with more than $4.2bn been paid into the Guyana Natural Resource Fund since first production in 2019.

In November 2023, ExxonMobil and Hess commenced production at the $9bn Payara oil development on the Stabroek Block.

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The duo, which holds the engineering, procurement, and construction (EPC) contract, was issued full notice to proceed from Cedar LNG LP partners, comprising the Haisla Nation and Pembina Pipeline.

To be built within the traditional territory of the Haisla Nation, the FLNG project will have a capacity to export three million tonnes per year (Mtpa) of LNG.

Black & Veatch will oversee the comprehensive topside design and equipment supply, leveraging its PRICO technology. On the other hand, Samsung Heavy Industries will deliver the hull with the containment system, in addition to handling the fabrication and integration of all topside modules.

Samsung Heavy Industries executive vice president and chief marketing officer SI Oh said: “Cedar FLNG has achieved another milestone of notice to proceed, solidifying an excellent partnership between SHI and Black & Veatch.

“Both of our firms continue to excel in FLNG market.”

During the peak of construction at the Cedar LNG project, a workforce of up to 500 individuals will be engaged. Once operational, approximately 100 personnel will maintain full-time positions at the facility.

The FLNG project has reached an advanced stage, securing major environmental approvals such as a British Columbia Environmental Assessment Certificate and a positive Decision Statement from the Canadian government.

A final investment decision (FID) on the project is anticipated to be made by the middle of this year. Its in-service date is projected to be in late 2028.

Cedar LNG will be the first indigenous majority-owned LNG project in the world. It will also be the first-ever FLNG to be electric-driven, powered by renewable energy sources.

Besides, it will be the first FLNG export facility in Canada. The project is expected to have low carbon intensity with renewable electricity powering essential components such as refrigeration compressors, boil-off gas compressors, and six centrifugal pumps.

Black & Veatch energy and process industries business president Laszlo von Lazar said: “Black & Veatch is committed to helping our clients and the communities they serve make meaningful progress on their decarbonisation journey.

“The Cedar LNG project represents important first steps toward reducing carbon emissions through lower-carbon LNG facilities, which can supply customers looking to move away from more carbon-intensive feedstocks.”

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Located 13km south of the Brage field, the Brasse development has an estimated 24 million barrels of oil equivalent gross in recoverable reserves. It will be developed as a two-well subsea tieback to the Brage field.

The Norwegian oil and gas field development will use the existing processing capacity on the Brage platform, where the initial production commenced in 1993.

OKEA operates PL740 with a stake of 39.3%. Other partners are DNO Norge, Lime Petroleum, and M Vest Energy with 39.3%, 17%, and 4.4% interests, respectively.

The Brage unit partnership includes OKEA as operator (35.2%), Lime Petroleum (33.84%), DNO Norge (14.25%), Petrolia Noco (12.25%), and M Vest Energy (4.44%).

OKEA intends to submit the plan for development and operation (PDO) this month. Following the approval of the PDO, the Brasse development will be renamed to Bestla.

The Norwegian oil and gas field development is anticipated to start operations during the first half of 2027, with operation expected to extend until 2031. It will also hold the potential for extension.

OKEA projects and technology senior vice president Knut Gjertsen said: “Brasse is an important addition to our portfolio and represents a significant value creation opportunity for OKEA and our partners.

“As a tie-back to Brage, both licences will benefit from synergies and economies of scale.”

OKEA has also awarded contracts pertaining to the offshore development to Aker Solutions, Subsea7, and OneSubsea.

Under its contract, Aker Solutions will provide engineering, procurement, construction, installation, and commissioning services for the Brage field. This involves preparing the platform’s topside to receive oil and gas from the Brasse field.

Subsea7 and OneSubsea have been awarded contract for the subsea scope of the Brasse development. Rig and drilling services contracts for the Norwegian field development will be awarded in Q2 2024.

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The deal has been approved unanimously by ChampionX’s board of directors.

As per its terms, ChampionX’s shareholders will exchange each of their shares for 0.735 shares of SLB. Following the closing of the deal, ChampionX’s shareholders will own a stake of around 9% in the enlarged SLB.

ChampionX provides chemistry solutions, artificial lift systems, and highly engineered equipment and technologies. It helps companies around the world in the exploration and extraction of oil and gas with a focus on safety, efficiency, and sustainability.

Recently, ChampionX announced the acquisition of RMSpumptools from UK-based James Fisher and Sons for $110m. RMSpumptools is engaged in designing and manufacturing highly engineered mechanical and electrical solutions for complex artificial lift applications.

ChampionX president and CEO Soma Somasundaram said: “We have been on a journey to build the best production-focused company in our sector, with a goal of unlocking energy through our differentiated products and technology as well as our strong financial engine.

“Becoming part of SLB will give us a much broader portfolio and the resources and reach to continue to lead the industry in providing energy to the world in an economically and environmentally sustainable way.

“Our companies share a vision for the future of energy that leverages technology and innovation to solve our customers’ most complex problems and better serve the communities in which we operate.”

According to SLB, the production phase of oil and gas operations usually is made up of the majority of an asset’s life cycle from completion till decommissioning. This puts a premium on the ability of service providers to assist customers cope with challenges spanning across their production system, said the company.

SLB also stated that at the same time, there is an increasing demand for scaling artificial intelligence (AI), autonomous operations, and other emerging technologies across operations around the world.

The portfolios of the two firms when combined is anticipated to propel customer value via deep industry expertise and digital integration, along with better equipment life and production optimisation.

SLB CEO Olivier Le Peuch said: “Our customers are seeking to maximise their assets while improving efficiency in the production and reservoir recovery phase of their operations.

“This presents a significant opportunity for service providers who can partner with customers throughout the entire production lifecycle, offering integrated solutions and delivering differentiated value.

“The combination of ChampionX’s strong production-focused leadership throughout North America and beyond with our own international presence, unmatched technology portfolio, and history of innovation will drive tremendous value for our customers and stakeholders.”

The deal is expected to generate pretax synergies of around $400m per year for SLB within the first three years after closing. This will be from growth in revenue and cost savings.

Likely to close by the year end, the transaction is contingent on ChampionX’s shareholders’ approval, regulatory approvals, and other customary conditions.

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The award was given by Shell’s subsidiary Shell do Brasil.

Under the contract, MODEC will handle the design of the hull and all associated topsides facilities for the Gato do Mato FPSO. The production vessel is expected to be moored by a SOFEC Spread Mooring system.

It will be tied at a water depth of around 2,000m, nearly 250km off the Brazilian coast.

The stabilized crude produced from the Gato do Mato development will be stored in the tanks of the FPSO. The oil drawn from the field will be delivered to the market using shuttle tankers.

To date, MODEC has executed 16 FPSO projects intended for Brazilian waters. Currently, the company has two more vessels under construction.

The FPSO Gato do Mato represents the second unit to be directly delivered by MODEC to Shell for operation in Brazil. The first FPSO delivered by MODEC to Shell for FPSO Fluminense, which has been operating in the Bijupirá and Salema oil fields in the Campos Basin since 2003.

MODEC president and CEO Hirohiko Miyata said: “MODEC is proud to be working on its nineteenth (19th) FPSO for Brazil and our second for Shell in Brazil. This milestone indicates the strong relationship between the two companies which now spans more than 20 years.

“We are excited about performing this FEED study for Shell.”

Earlier this year, MODEC and Toyo Engineering had awarded a contract to ABB pertaining to an FPSO vessel in the Uaru oil field operated by ExxonMobil in Guyana.  The contract was awarded through their joint venture Offshore Frontier Solution.

As per the contract, ABB will be responsible for providing a complete electrical system and related digital solutions to the FPSO named Errea Wittu.

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The Block B project includes an upstream gas field, located 330km offshore southeast Vietnam, along with a 433km long associated pipeline that will connect the field to a gas-fired thermal power plant complex.

Mitsui is taking part in the project through its 100% owned subsidiary Mitsui Oil Exploration (MOECO). The latter via its subsidiaries, which are joint ventures with JOGMEC, holds a stake of 23% in the gas field.

According to Mitsui, the group has wrapped up awarding associated contracts alongside its partners pertaining to the integrated development project.

Vietnam Oil and Gas Group (PVN) has an operating stake of 42% in the upstream part of the project. PetroVietnam Exploration Production (PVEP), which is a subsidiary of PVN, holds a 27% stake while Thailand-based PTT Exploration and Production (PTTEP) has an 8% stake.

PetroVietnam Gas (PV Gas), a subsidiary of PVN has a 51% stake in the pipeline while PVN holds a 29% stake. MOECO, through a 100% subsidiary has a 15% stake, while PTTEP owns a stake of 5%.

The upstream project involves the drilling of 37 wells before production and 861 wells in total through project life. The aim of the project is to draw 490 million cubic feet per day (mmcf/d) of gas, which is around 84,500 barrels of oil equivalent per day (boe/d).

Mitsui’s share in the development of the gas field will be $560m. In the pipeline project, the group’s share will be $180m.

The pipeline will be 330km offshore and 103km onshore. Its maximum transportation capacity will be 640mmcf/d (or around 110,000boe/d).

Mitsui stated: “The Block B Project will be the next-generation core business for MOECO. MOECO has been participating in this highly competitive project from the exploration phase and the project is expected to yield stable earnings in the long-term.

“Production capacity is estimated to be 490 million cubic feet per day, with production scheduled to begin by the end of 2026.”

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The offshore block is operated by their joint venture, Al Yasat Petroleum. It is made up of the three fields, Belbazem, Umm Al Salsal, and Umm Al Dholou.

ADNOC upstream executive director Abdulmunim Saif Al Kindy said: “The start of crude oil production from the Belbazem offshore block is testament to the success of our strategic partnership with CNPC and the robust bilateral energy relationship between the UAE and China.

“ADNOC continues to maximise value from Abu Dhabi’s resources, while reducing our carbon footprint to ensure a secure, reliable, and responsible supply of energy to customers locally and internationally.”

According to ADNOC, the Belbazem offshore block’s production capacity is expected to be ramped up gradually to 45,000 barrels per day (bpd) of light crude alongside 27 million standard cubic feet per day (mmscfd) of associated gas.

The block will thus help ADNOC in attaining its target of five million bpd by 2027 while bringing gas self-sufficiency for the UAE.

Situated 120km northwest of Abu Dhabi city, the Belbazem block is exploiting operational synergies by using the facilities of the Satah Al Razboot (SARB) offshore field, which is operated by ADNOC Offshore. This will lead to cost savings as well as reduced impact on the environment, said ADNOC.

The block is using an artificial intelligence (AI) tool called WellInsight from AIQ for analysing reservoir data apart from managing operations for improved safety and performance.

ADNOC said that the block will also incorporate advanced technologies, which are already in use at the Al Yasat’s Bu Haseer offshore field. This will help with production optimisation and management of the reservoir, said the company.

In 2021, ADNOC awarded a contract worth AED2.73bn ($740m) to the National Petroleum Construction Company (NPCC) for the full field development of Belbazem. The UAE-based NPCC handled the engineering, procurement, and construction (EPC) of the offshore facilities of the project under the contract.

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The JV will develop, build, own, and operate natural gas pipeline and storage assets to address growing liquefied natural gas (LNG) and US Gulf Coast (USGC) demand.

Enbridge will hold a 19% stake in the JV, while WhiteWater and I Squared will have a combined 50.6% share. The remaining 30.4% stake will be owned by MPLX.

As per the terms of the agreement, Enbridge will contribute its 100% owned Rio Bravo pipeline project and around $350m in cash for the JV stake. The Canadian midstream firm will retain an economic interest of 25% in the pipeline project as part of its investment.

The Rio Bravo pipeline, which will be about 220km long, is being built to bring natural gas from the Agua Dulce supply area to the Rio Grande LNG project owned by NextDecade in Brownsville, Texas.

The JV will combine the Rio Bravo pipeline project with the nearly 724km long Whistler natural gas pipeline, which connects the Permian Basin to Agua Dulce, Texas. Currently, the Whistle pipeline is owned jointly by WhiteWater and MPLX.

According to the parties, the JV will also include 70% ownership in the proposed 64km long ADCC natural gas pipeline, owned by Whistler Pipeline and Cheniere Energy. This intrastate pipeline is expected to bring 1.7 billion cubic feet per day (Bcf/d) of gas from the Whistler gas pipeline’s terminus in Agua Dulce to the Corpus Christi LNG export facility owned by Cheniere Energy.

The new JV will have a 50% stake in the Waha Gas Storage project. Owned by WhiteWater, Waha Gas Storage is made up of underground salt caverns located in Pecos County, Texas with a storage capacity of around 2Bcf.

Enbridge EVP and gas transmission and midstream president Cynthia Hansen said: “Acquiring a meaningful equity interest in an integrated Permian natural gas pipeline and storage network that is directly connected to our existing infrastructure at Agua Dulce through this JV with WhiteWater/I Squared and MPLX is very exciting.

“This is a great way to enhance our super-system approach, bringing energy supply to places where it is needed most and providing last mile connectivity to domestic and export customers.”

The JV deal, which is contingent on the necessary regulatory approvals and other conditions, is anticipated to close in Q2 2024.

WhiteWater will continue to operate the assets involved in the JV, including the Rio Bravo pipeline project.

WhiteWater CEO Christer Rundlof said: “This strategic transaction is a win for WhiteWater/I Squared and MPLX. It extends the average contract tenor, brings us closer to an important strategic partner in Enbridge and positions us well for future development opportunities supporting Gulf Coast LNG.”

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