OGJ Newsletter

 GENERAL INTEREST Quick Takes

UK to lift hydraulic fracturing moratorium

UK Prime Minister Liz Truss will lift the country’s moratorium on hydraulic fracturing in addition to pursuing other measures to accelerate development of domestic energy supplies.

“Far from being dependent on the global energy market and the actions of malign actors, we will make sure that the UK is a net energy exporter by 2040,” she said during her opening speech on the energy policy debate in the House of Commons Sept. 8.

PM Truss said the government will accelerate “all sources of domestic energy, including North Sea oil and gas production,” and expects a new licensing round to launch, leading to “over 100 new licenses being awarded,” she said. In addition, she envisions the country speeding up deployment of “all clean and renewable technologies including hydrogen, solar, carbon capture and storage, and wind.”

Fracturing was banned in 2019 after a report by the Oil and Gas Authority (OGA) stated that it was not possible to accurately predict the likelihood and strength of earthquakes linked to fracturing operations (OGJ Online, Nov. 4, 2019). This concern was raised after a series of seismic tremors occurred at the Preston New Road (PNR) Lancashire shale exploration site operated by Cuadrilla Resources near Blackpool.

At the time, Andrea Leadsom, minister for business, energy, and industrial strategy, said that the moratorium was to remain in place until compelling new evidence showed that shale gas extraction is safe.

In February 2022, Cuadrilla was ordered under the ban to plug and abandon Britain’s first two horizontal shale wells at PNR by the OGA (OGJ Online Feb. 10, 2022).

Since PM Truss’s speech, operators have voiced support for developing hydrocarbon resources through fracturing in the UK. Ineos, for example, has renewed an offer it made to the UK government in April to develop a fully functioning shale test site to demonstrate that the technology can be safe and secure in the UK.

OPEC sticks to 2022, 2023 oil demand forecast

The Organization of the Petroleum Exporting Countries (OPEC) is maintaining its forecast for strong growth in global oil demand in 2022 and 2023, citing signs that major economies are doing better than expected despite headwinds such as soaring inflation.

Oil demand will rise by 3.1 million b/d in 2022 and 2.7 million b/d in 2023, unchanged from the previous month, OPEC said in its monthly report.

“Oil demand in 2023 is expected to be supported by a still-solid economic performance in major consuming countries, as well as potential improvements in COVID-19 restrictions and reduced geopolitical uncertainties,” OPEC said.

The group and allies including Russia, known as OPEC+, have been boosting oil production this year as they look to lift record output cuts imposed in 2020 following a drop in demand due to the pandemic. However, OPEC+ has failed to deliver on its planned output increase in recent months due to underinvestment in oil fields by some OPEC members and falling Russian output.

OPEC’s monthly report showed that OPEC’s production increased in August, rising by 618,000 b/d to 29.65 million b/d, largely due to Libya’s recovery from disruptions.

Eni to acquire bp’s upstream business in Algeria

Eni SpA agreed to acquire bp’s upstream business in Algeria, including the gas-producing In Amenas and In Salah concessions, which produced a combined 11 billion cu m gas and 12 million bbl condensate and LPG in 2021.

bp holds working interests of 33.15% and 45.89% in the In Salah dry gas and In Amenas projects, respectively. Both are operated by joint ventures (JV) co-owned by bp, Equinor, and Sonatrach.

The In Salah gas JV has developed seven gas fields in the southern Sahara (Teg, Reg, Krechba, Gour Mahmoud, In Salah, Garet el Befinat, and Hassi Moumene), about 1,200 km south of Algiers. Production began in 2004. A second phase began in 2016. Production capacity is 9 billion cu m/year (bcmy), according to partner Equinor’s website. Part of the gas is marketed in Europe on the basis of a long-term sales and purchase agreement. 

The In Amenas JV produces gas and natural gas liquids from Illizi basin in southeastern Algeria. Production began in 2006. Production capacity is 9 bcmy, according to Equinor’s website.  

These acquisitions follow on the heels of recently signed contracts by Eni for Blocks 404 and 208 in Berkine basin, further increasing Eni’s assets in the country (OGJ Online, July 20, 2022).

Upon closing, subject to government approvals, partner pre-emption processes, and competition clearances processes, Eni will hold 45.89% interest in In Amenas and 33.15% interest in In Salah.

EQT to buy THQ Appalachia, adding 800 MMcfd of gas production

EQT Corp. has agreed to buy THQ Appalachia I LLC (Tug Hill) and THQ-XcL Holdings I LLC, acquiring Tug Hill’s upstream assets and XcL Midstream’s gathering and processing assets.

The Tug Hill purchase will add 800 MMcfd of natural gas equivalent production across 90,000 core net acres in southwest Appalachia to EQT’s portfolio. It includes roughly 300 remaining net risked locations, which the company says compete favorably with its adjacent assets and provide additional wet-gas production optionality.

Buying XcL Midstream brings EQT 95 miles of midstream gathering with connectivity all interstate transmission carriers operating in the region. The system will give EQT 1 bcfd of rich- and 3.5 bcfd of lean-gas deliverability, the 225-MMcfd Clearfork gas processing plant, and 20,000 b/d of condensate stabilization.

The companies expect the $5.2-billion transaction—$2.6 billion cash and $2.6 billion in stock—to close fourth-quarter 2022, with an effective date of July 1, 2022. Tug Hill and XcL Midstream are backed by equity commitments from funds managed by Quantum Energy Partners.

 Exploration & Development Quick Takes

ConocoPhillips drills dry hole near Balder field

ConocoPhillips Skandinavia AS drilled a dry hole in the central part of the North Sea about 30 km northwest of Balder field and 205 km west of Stavanger in 127 m of water. Exploration well 25/7-10 is classified as dry with oil shows. Licensees will assess the result as it pertains to further prospectivity in the license. Data acquisition and sampling have been carried out and the well has been permanently plugged.

The exploration well, the second in production license (PL) 782 S, was drilled by the Transocean Norge drilling rig to a vertical depth of 4,470 m subsea. It was terminated in the Heather formation in the Middle Jurassic.

The objective was to prove petroleum in Upper Jurassic reservoir rocks (the Intra-Draupne formation).

The well encountered thin sandstone layers totaling about 14 m in the Draupne formation with poor reservoir quality. Oil was collected from an isolated sandstone layer with limited extension, which is why no recoverable volumes can be estimated from this interval.

In the Heather formation (Middle Jurassic), the well encountered 29 m of sandstone with poor reservoir quality.

ConocoPhillips Skandinavia is operator at PL935 (40%) with partners Equinor Energy AS (20%), Aker BP ASA (20%), and Wintershall Dea Norge AS (20%).

Strike confirms West Erregulla-3 as significant producer

Strike Energy Ltd. confirmed a ‘substantial’ gas reserve in Western Australia’s onshore North Perth basin in permit EP469 through a completed test program at West Erregulla-3 appraisal well.

The 7-day multi-rate test program, across a 40 m interval in the Kingia sandstone reservoir at a depth of 4,733 m, recorded continued high-flowing wellhead pressures. The well remained stable during the 5-hr high-rate test which was constrained by well testing equipment and recorded 83 MMcfd of gas with a flowing wellhead pressure of 3,474 psi on a 68/64-in. choke.

The well was shut in after the test and wellhead pressure returned to near original reservoir pressure after 3 hours, indicating the quality of the reservoir and the presence of a substantial connected gas volume beyond the well bore, Strike said.

There was no sand or formation water produced during the test and the quality was recorded as a low-impurity dry gas, in line with gas compositions from the field and the region.

Strike is operator with 50% interest. Warrego Energy Ltd. holds the remaining 50%.

 Drilling & Production Quick Takes

Repsol aims for October restart at Yme field

Repsol Norge AS expects to restart production of Norwegian Shelf Yme field in early October after damage to parts of the process pipe system resulted in production downtime. The technical issues are likely to result in a total of 5-6 weeks of production downtime at the field as repair work is conducted, partner OKEA ASA said in a release Sept. 9.

Yme includes production license (PL) 316 and PL 316 B in the southeastern part of the Norwegian North Sea in Block 9/2 and 9/5 in Egersund basin, 130 km from the Norwegian coastline. Expected recoverable reserves in Yme are estimated to be about 10 million std cu m oil (63 million bbl). At plateau, the field will produce around 56,000 boe/d.

In October 2021, Repsol and partners achieved first oil from Yme field restart after it was shut down in 2001 in response to low oil prices (OGJ Online, Oct. 25, 2021).

Repsol Norge is operator of Yme field with a 55% working interest. Partners are Lotos Exploration and Production Norge AS (20%), KUFPEC Norway ASA (10%), and OKEA ASA (15%).

ADNOC lets framework awards worth $1.83 billion

Abu Dhabi National Oil Co. (ADNOC) has awarded five framework agreements valued at $1.83 billion (AED6.72 billion) for directional drilling and logging while drilling (LWD).

Contracts were let to Al Ghaith Oilfield Supplies and Services Co., Al Mansoori Directional Drilling Services, Schlumberger Middle East SA, Haliburton Worldwide Ltd. Abu Dhabi, and Weatherford Bin Hamoodah Co. LLC, the company said in a release Aug. 31.

The awards cover ADNOC’s onshore and offshore fields and will run for 5 years with an option for a further 2 years.

The awards will support ADNOC’s requirement to drill thousands of new wells to expand its production capacity to 5 million b/d by 2030, enable gas self-sufficiency for the UAE, and remain a leading low-cost, low-carbon oil producer, the company said.

Since November 2021, ADNOC has awarded drilling agreements worth over $11 billion to contractors for wellheads and related components, downhole completion equipment and related services, liner hangers, cementing services, wireline logging, and directional drilling.

TMK to drill extra Mongolian coal seam gas appraisal well

TMK Energy Ltd. and JV partner Talon Energy Ltd. will expand the appraisal drilling program at the Snow Leopard coal seam gas prospect in the Gurvantes XXXV Project in South Gobi basin of southern Mongolia.

Snow Leopard-05 (SL-05) will be drilled mid-way between SL-02 and SL-04 in the eastern half of the prospect to a depth of around 650 m.

The new well presents a low-cost opportunity (US$100,000) to gather additional data on the upper and lower coal seams, TMK said.

Drilling continues on the SL-03R well to target the lower coal seam adjacent to where the upper seam was intersected in SL-03. It will take another 2 weeks to complete and test.

Results of all five wells in the 2022 program will be incorporated into the dataset to determine the company’s maiden contingent resource assessment, which should be completed in October. Results also will aid in planning the pilot well program.

In August, TMK executed a memorandum of understanding with PetroChina which has expressed interest in the Guvantes project.

TMK envisions sending Snow Leopard natural gas production to the Chinese market across the Mongolian border by pipeline.

 PROCESSING Quick Takes

Vertex delays Alabama refinery renewables project

Houston-based Vertex Energy Inc., a specialty refiner of alternative feedstocks, is postponing mechanical completion of its $90-100 million renewable diesel conversion project at subsidiary Vertex Refining Alabama LLC’s 75,000-b/d refining and petrochemical complex in Mobile, Ala., amid ongoing supply chain disruptions and procurement delays in bulk-material markets.

The strategic extension of the original construction timeline for the project to modify the refinery’s existing hydrocracking unit to produce renewable diesel fuel on a standalone basis results from COVID-19-induced product delays and global supply chain shortages in several previously unimpacted markets, including common pipes, valves, fittings, and certain base bulk materials, Vertex said on Sept. 13.

To ensure all necessary parts and materials are ready and on site ahead of shutting down the hydrocracker to execute conversion works—which was planned to occur in October 2022— Vertex said it is extending mechanical completion to first-quarter 2023 for targeted startup of the revamped unit’s initial 8,000-10,000 b/d of renewable diesel production in second-quarter 2023.

Deferral of construction works delays the project’s overall timeline by a quarter from previous targets for mechanical completion and production startup by yearend 2022 and first-quarter 2023, respectively.

The converted unit’s renewable diesel production volumes will subsequently ramp up to about 14,000 b/d, according to the operator.

Vertex said it expects its decision to extend the project’s timeline will result in a positive impact of about $15-17 million to its fourth-quarter 2022 gross margin by maintaining current operating levels through yearend 2022.

Despite the incremental delay, Vertex said the project remains on budget, with procurement of items with long lead times already completed. Construction of foundations and fabrication of piping for the project also are currently under way, the operator told investors in a presentation Aug. 9.

During second-quarter 2022, the Mobile refinery’s crude oil throughput averaged 72,133 b/d and a production rate of 71,755 b/d for an overall quarterly utilization rate of 96%, Vertex said.

Once operable, the Mobile refinery’s converted hydrocracking unit—which previously produced olefins as feedstock for petrochemical manufacturers—will be capable of processing a wide range of organic, pretreated feedstocks, including soybean and corn oil, meat tallow, and waste vegetable oils, among others, according to the operator’s website.

Imperial lets contract for planned Strathcona renewable diesel complex

ExxonMobil Corp.’s majority owned affiliate Imperial Oil Ltd. let a contract to Air Products Inc. to supply low-carbon hydrogen for Imperial’s proposed grassroots renewable diesel production complex to be built at its 196,000-b/d Strathcona refinery near Edmonton, Alta., in western Canada.

As part of the Sept. 6 contract, Air Products will provide the Strathcona refinery’s planned complex long-term supply of about 50% of clean hydrogen produced by subsidiary Air Products Canada Ltd.’s 165-MMcfd net-zero hydrogen production and liquefaction complex currently under construction in Edmonton, Imperial and Air Products said in a joint release.

To support the contract award from Imperial, Air Products also has agreed to increase its original $1.3-billion (Can.) overall investment in the Edmonton hydrogen complex to $1.6 billion. Air Products said it will use its additional investment to carry out works to enable integration with the proposed renewable diesel project and help further reduce emissions at its own Edmonton hydrogen production hub.

Following delivery to the Strathcona site via pipeline, Air Products’ supply of blue hydrogen—or hydrogen produced from natural gas with carbon capture and storage (CCS) technology—will be combined with locally sourced renewable feedstocks and a proprietary catalyst to produce more than 1 billion l./year (roughly 20,000 b/d) of low-carbon, renewable diesel to reduce greenhouse gas emissions from Canada’s transportation sector by about 3 million tonnes/year (tpy).

Currently still in discussions with the government of Alberta, industry, and the government of British Columbia—the latter of which has agreed to support the project in the form of credits under its provincial low carbon fuel standard—Imperial expects to take final investment decision on the proposed renewable diesel project in fourth-quarter 2022.

If approved, the complex would begin production in 2024.

Under development since 2018 and formally announced in June 2021, Air Products’ proposed Edmonton net-zero hydrogen production and liquefaction complex—like Imperial’s Strathcona renewable diesel project—comes as a government-supported project to help Alberta reduce its provincial carbon footprint.

Scheduled for startup in 2024, the hydrogen complex will deliver net-zero emissions by capturing more than 95% the CO2 generated at the site for permanent sequestering underground, with hydrogen-fueled electricity to offset the remaining 5% of emissions, Air Products said in a June 2021 release.

Designed to help refining and petrochemical customers served by the operator’s 55-km Alberta Heartland hydrogen pipeline, the complex also will enable production of liquid hydrogen to be used as emissions-free fuel in the Canadian transportation sector, and for generation of clean electricity, according to Air Products.

To become the world’s largest net-zero hydrogen complex upon commissioning, the site will include the following:

• An auto-thermal reformer (ATR) hydrogen production plant equipped with proprietary technology from Topsoe AS.
• Carbon-capture operations capable of achieving 95% removal of CO2, which will be permanently sequestered by leveraging the Wolf Carbon Solutions Inc.’s wholly owned and operated Alberta Carbon Trunk Line.
• A power-generation plant fueled 100% by hydrogen—including NovaLT16 turbines provided by Baker Hughes—to produce clean electricity for the entire complex and export to the grid, offsetting the remaining 5% CO2 to achieve the complex-wide net-zero design.
• A 35-tonnes/day (previously 30-tonnes/day) hydrogen liquefaction plant designed by Air Products.
• An air-separation designed by Air Products to support the ATR operation and to produce clean liquid oxygen and nitrogen for the merchant industrial gas market.
• Connection to Air Products’ existing Alberta Heartland hydrogen pipeline network for enhanced reliability and phased decarbonization of the entire network. 

 TRANSPORTATION Quick Takes

Woodside deal signed to supply LNG to Europe

Woodside Energy Trading Singapore Pte Ltd. entered a flexible long-term agreement with Uniper Global Commodities SE to supply LNG cargoes into Europe.

Uniper has been looking for replacements for Russian gas sources cut off following Russia’s invasion of Ukraine.

Up to 12 cargoes per year (over 0.8 million tonnes/year) will be sent to Europe beginning in January 2023 for a term of up to 16 years until 2039, Uniper said. Supply from September 2031 will be conditional on Uniper finalizing its long-term strategic capacity bookings in northwest Europe, expected in March 2023.

The agreement with Woodside secures additional LNG supplies for Uniper customers in Europe, said Klaus-Dieter Maubach, Uniper Group chief executive.

Russian gas flows to Europe have fallen to 1,600 terajoules/day in early September from over 17,000 terajoules/day at end 2020, according to media reports. The 91% drop in Russian gas supplies is equivalent to 95 million tonnes/year (tpy) of LNG.

Uniper is already contracted to buy an initial 1 million tpy of LNG a year from Woodside, increasing to 2 million tpy from 2026, provided Woodside’s Scarborough LNG project off Western Australia attains planned development.

QatarEnergy awards heat exchanger contract for North Field East

QatarEnergy has awarded Air Products Inc. a contract to supply four end-flash coil-wound heat exchangers (CWHE) for North Field East LNG project in Ras Laffan Industrial City, Qatar. One end-flash CWHE will be used with each of the four 8-million tonne/year AP-X LNG process trains Air Products is building for Chiyoda Corp. and Technip Energies, who are constructing the project’s LNG plant.

The Chiyoda-Technip joint venture last year won the engineering, procurement, construction, and commissioning contract for North Field East’s onshore infrastructure. Start-up of the first North Field East LNG train is planned for end 2025.

Air Products has supplied the 14 LNG trains already operating at Ras Laffan.

Alexandroupolis INGS hires project management firms

Alexandroupolis Independent Natural Gas System (INGS), owned and developed by Gastrade AE, has awarded a partnership of RINA SPA and Asprofos Engineering SA a contract to provide project management consultancy services. INGS will consist of an 8.3-billion cu m/year (bcmy, 800 MMscfd) permanently moored floating storage and regasification unit (FSRU) and a 28-km pipeline connecting the FSRU to the Greek transmission system.

The 153,000-cu m FSRU will be stationed in the northeastern Aegean Sea, 17.6 km southwest of Alexandroupolis in northeast Greece. The FSRU’s nominal gas send out rate will be 5.5 bcmy, which the companies intend to have online by end-2023.

The 30-in. OD pipeline will have a maximum operating pressure of 110 barg. It will run 24-km subsea and 4-km onshore, making landfall near Apalos and delivering to a Hellenic Gas Transmission System Operator metering and regulating station near Amfitriti, Greece.

Gastrade has also applied to Greek regulators for a separate INGS license to develop FSRU-based Thrace LNG.

Group developing Germany’s fifth LNG terminal charters Excelerate FSRU

Tree Energy Solutions (TES) GMBH, E.ON SE, and Engie SA will jointly develop a fifth floating storage and regasification unit (FSRU) in Wilhelmshaven, Germany, having been selected by the German Federal Ministry of Economics and Climate Protection (BMWK) to execute the project. The companies are planning a fourth-quarter 2023 start of operations for the 5-billion cu m/year FSRU.

Engie chartered the FSRU for a 5-year term from Excelerate Energy LP on behalf of the BMWK.

TES and E.ON are building a green energy hub, including a hydrogen terminal, in Wilhelmshaven, Germany (OGJ Online, Apr. 28, 2022). TES says the FSRU will accelerate development of the hydrogen terminal, which TES has been developing since 2019 and plans to start for large-scale imports by 2025.

TES’s hub will ultimately include six berths, 2 million cu m of onshore storage using 10 tanks, and direct access to natural gas, hydrogen, and CO2 pipeline networks.