OGJ Newsletter

July 19, 2021


Australia awards first Beetaloo basin funding grant

Empire Energy has been awarded three grants worth up to $21 million (Aus.) by the Australian government under its Beetaloo Cooperative Drilling Program announced earlier this year.

The grants will provide support for new exploration wells in Empire’s 100%-owned EP187 exploration permit in the Northern Territory Beetaloo basin.

The funds will offset 25% of eligible expenditure which may include additional seismic acquisition, the drilling of up to three horizontal wells in 2021 and 2022, fracture stimulation, and completion of the wells along with flow testing. The first horizontal appraisal well is expected to spud in this year’s fourth quarter.

The government program provides for $50 million of funding towards exploration activity carried out in the basin by end 2022. The maximum grant under the program is $7.5 million per well, capped at 25% of the cost of each well and three wells per venture. Related support activities, such as seismic acquisition and flow testing, are eligible under the program.

Empire Energy is the first company to receive approvals under the scheme.

Lukoil to acquire offshore Mexico asset from Fieldwood

PJSC Lukoil agreed to acquire the 50% operator interest in the Area 4 project offshore Mexico owned by Fieldwood Energy LLC, Houston, which entered bankruptcy in 2020.

The Russian company will acquire Fieldwood’s holding company in a transaction valued at $435 million plus expenditures incurred in 2021 as of the transaction completion date, which is subject to conditions, including approval by Mexican authorities, the company said in a statement July 5.

Area 4 includes two blocks totaling 58 sq km, which lie 42 km offshore Mexico in the Gulf of Mexico in 30-45 m water. Oil fields Ichalkil and Pokoch lie within the blocks in the Bay of Campeche. Estimated recoverable hydrocarbon reserves of the fields are 564 MMboe (over 80% crude oil).

Production infrastructure construction is being finalized, and first oil is expected in this year’s third quarter. The project is being developed in three phases under a 25-year production sharing agreement signed in 2016 with an optional extension of up to 10 years. Estimated peak daily production is over 115,000 boe.

PetroBal, the oil and gas subsidiary of GrupoBAL, holds the remaining 50% interest.

TotalEnergies, Veolia developing CO2-based microalgae cultivation

TotalEnergies SE and Veolia Environnement SA are working together to accelerate development of microalgae cultivation using CO2 via a 4-year research project at TotalEnergies’ La Mède biorefinery on the French Riviera.

The partners will set up a test platform to compare different systems for growing microalgae and identify the most efficient ones for the purpose of producing biofuel.

TotalEnergies commissioned the 500,000-tonne/year plant at La Mède in mid-2019, producing biofuels from used oils and other renewable feedstocks. Conversion of the former 153,000-b/d crude oil refinery cost €275 million ($326 million).

Equinor, US Steel to study CCS, hydrogen

Equinor US Holdings Inc., an affiliate of Equinor ASA, and United States Steel Corp. (US Steel) have executed a nonexclusive MoU to study the potential for carbon capture and storage (CCS) and hydrogen development in the tri-state region of Ohio, Pennsylvania, and West Virginia.

The companies plan to explore and demonstrate potential opportunities for natural gas when coupled with CCS to achieve decarbonization goals. US Steel has targeted net-zero emissions by 2050.

The MoU also includes assessments of regional hydrogen and CCS potential, appropriate customer and supplier screenings, blue hydrogen advocacy, CCS, and examining what the companies describe as renewable energy synergies.

 Exploration & Development Quick Takes

Eni to tie back new discovery in Block 4, offshore Ghana

Eni SPA will tie-in its new Eban exploration discovery offshore Ghana to the John Agyekum Kufuor FPSO. The well lies 50 km off the coast and 8 km northwest of Sankofa Hub.

Eban-1X is the second well drilled in CTP Block 4 following the Akoma discovery. It was drilled by the Saipem 10000 drillship in 545 m of water and reached a measured depth of 4,179 m. The well proved a single light 80 m thick oil column in a thick sandstone reservoir interval of Cenomanian age, encountering hydrocarbons down to 3,949 m true vertical depth.

The discovery has been assessed following analysis of 3D seismic datasets and well data acquisition including pressure measurements, fluid sampling, and formation testing. Pressure and fluid data (oil density and gas-to-oil ratio) and reservoir properties are consistent with the Akoma discovery and nearby Sankofa field. Production testing data show a well deliverability potential estimated at 5,000 b/d similar to producing wells from Sankofa field.

Estimated hydrocarbon from Sankofa field and the Eban-Akoma complex is now more than 1.1 billion boe.

Eni is operator of the CTP Block 4 joint venture with partners Vitol, GNPC, Woodfields, and GNPC Explorco.

OKEA lets subsea contract for Hasselmus project

OKEA ASA has let a subsea contract to Subsea Integration Alliance (formed by Subsea 7 SA and OneSubsea, a Schlumberger Ltd. division), for the Hasselmus project, 7 km northwest of the Draugen platform in the southern Norwegian Sea.

The Draugen license operator and partners Petoro AS and Neptune Energy Norge AS are developing the gas discovery—the first tie-back to the Draugen platform—which is expected to add over 4,000 boe/d to production, OKEA said in June.

Work scope covers engineering, procurement, construction, and installation of the subsea production systems and subsea pipelines (SURF) for a single subsea well with direct tie-back to Draugen (OGJ Online, May 6, 2021). The SURF scope comprises about 9 km of pipe-in-pipe flowline and associated structures in water depths of about 250 m.

The Hasselmus reservoir contains gas in sandstone of early Jurassic age in the Ile and Ror formations. The company is working toward a 2023 production start.

Project management and engineering will commence immediately at Subsea 7’s offices in Stavanger. Fabrication of the pipelines will take place at Subsea 7’s spoolbase at Vigra, and offshore operations will be executed in 2022 and 2023. 

CNOOC takes delivery of Buzzard Phase II module

China National Offshore Oil Corp. International Ltd. (CNOOC) has taken delivery of a new topsides module for Buzzard Phase II in the North Sea’s Outer Moray Firth, about 96 km northeast of Aberdeen in about 96 m of water.

Housing process, utilities, and controls equipment, the 27-m long, 18-m tall, 516-tonne unit was loaded on board from the Worley Rosenberg fabrication facility in Stavanger, transported to the field, and subsequently installed by Allseas’s Pioneering Spirit construction vessel on the southwest corner of the Buzzard production platform for hook up and commissioning.

Buzzard Phase II is a subsea development about 5 km northeast of Buzzard, consisting of a 12-slot manifold (eight production and four water injection slots). The development will tie back to the existing Buzzard complex with a pipeline bundle assembly incorporating pipelines, manifolds, subsea controls, and chemical injection. A brownfield module is to be installed on the production platform for processing and export via current export pipeline routes. Phase II production is expected to commence in 2021.

CNOOC is operator at Buzzard with partners Suncor Energy Inc., Chrysaor Norge AS, and ONE Dyas BV.

 Drilling & Production Quick Takes

State Gas confirms additional deep gas production at Reid’s Dome

State Gas Ltd., Brisbane, has confirmed that coal seam gas is being produced from depths below 1,150 m at its Reid’s Dome field in the Bowen basin of southeast Queensland.

The flow is in addition to the known production from coal seams at 400-1,000 m.

The company had been production testing the Nyandra-4, Nyandra-7, and Nyandra-8 wells at its 100%-owned project when gas flow data from tests indicated gas was also being produced from lower seams.

The flow was confirmed with a production log test at Nyandra-4. The well intersected 40 m of net coal at 394-1,177 m with the lowest coals positioned just above the bottom of the well at 1,200 m depth. Temperature and noise logs were run to determine which zones were producing gas.

Results showed good flows from the top coals at 400-600 m and, importantly, also from the bottom section of the well below 1,150 m, which is much deeper than is typical for the region.

The outcome is commercially important for Reid’s Dome and the area within the PL 231 permit as the coal seams dip down away from the crest of the dome.

State Gas can produce economically at depths exceeding 1,000 m naturally, unaided by stimulation, said Executive Chairman Richard Cottee.

On test completion, Nyanda-4 was returned to production. It is currently producing 138,000 cu ft/day (cfd). Nyandra-7 and -8 are producing at 7,000 cfd and 38,000 cfd, respectively.

Equinor drills dry hole south of Troll

Equinor Energy AS drilled a dry hole in production license (PL) 785 S, about 55 km south of Troll field in the North Sea and 100 km southwest of Bergen in 289 m of water. Data acquisition was carried out. The well will be plugged.

Well 31/11-1 S, the first in the license, was drilled by the Deepsea Atlantic drilling rig to 3,254 m measured depth and 3,135 m vertical depth below sea level. It was terminated in the lower part of the Statfjord Group from the Early Jurassic to Late Triassic.

The primary target was to prove petroleum in the Johansen formation from the Early Jurassic and the Statfjord Group from the Late Triassic to Early Jurassic.

The secondary target was to prove petroleum and investigate reservoir properties in the Sognefjord formation, the Fensfjord formation, the Brent Group (Late to Middle Jurassic), and source rock potential in this part of the Stord basin. Another objective was to evaluate reservoir properties for CO2 storage.

The well encountered 65 m of the Johansen formation, of which 48 m were sandstone with moderate reservoir quality. The well also encountered 28 m of sandstone with moderate reservoir quality in the upper part of the Statfjord Group.

In the secondary target, the well encountered 275 m of the Sognefjord formation of which 65 m were sandstone of moderate to good reservoir quality. It also encountered about 130 m of the Fensfjord formation of which 47 m were sandstone with moderate to good reservoir quality. The Brent Group was not encountered.

The rig will now drill production well 34/7-J4 AH on Tordis field in Equinor-operated PL 089 in the North Sea.

Equinor is operator at PL 785 S in a 50-50 partnership with Total E&P Norge AS.

SDX Energy starts two-well South Disouq drilling campaign

SDX Energy PLC started the South Disouq drilling campaign in Egypt, which will consist of one step-out development well and one exploration well.

The development well, IY-2, was spudded on June 28. It is targeting the high porosity and permeability Basal Kafr El Sheikh reservoir at about 6,600 ft in Ibn Yunus field. The well will take about a month to drill and will be tied into existing infrastructure at the nearby IY-1X well. Production is expected to start in late third-quarter 2021. The well will maximize recovery from the field and help to maintain current gross production levels of about 45 MMscfd at the South Disouq central processing plant.

The exploration well, HA-1X, on the Hanut prospect, is expected to spud after completion of IY-2 in early August. The well is targeting gross unrisked mean recoverable volumes of 139 bcf with a 33% chance of success.

SDX Energy is operator at South Disouq with 55% interest. IPR Energy Group holds the remaining 45%.


Shell to sell interest in German JV refinery

Vienna-based Alcmene GMBH, a subsidiary of privately owned Liwathon EOS of Estonia, has entered an agreement with Royal Dutch Shell PLC for the purchase of Shell Deutschland Oil GMBH’s 37.5% minority interest in PCK Raffinerie GMBH’s 220,000-b/d refinery in Schwedt, Germany, located along Druzhba pipeline in Schwedt, Germany, about 120 km northeast of Berlin.

Pending approval by PCK Raffinerie’s remaining joint venture partners PJSC Roseneft subsidiary Rosneft Deutschland GMBH (54.17%) and Eni SPA subsidiary Eni Deutschland GMBH (8.33%) as well as other regulatory approvals, the transaction is slated to close by yearend, Shell said on July 8.

While it did not reveal specific details regarding an overall value of the proposed sale, Shell said hydrocarbon inventory included as part of the deal—which range between $150-250 million—would be valued at closing based on actual volumes and prevailing market prices.

The sale will support further development of Shell’s Rheinland energy and chemicals park, according to Robin Mooldijk, Shell’s executive vice-president of manufacturing.

The Rheinland energy and chemicals park includes Shell Deutschland’s 140,000-b/d refinery at Wesseling, Germany, which together with the former Godorf refinery near Cologne-Godorf, form the 325,000-b/d integrated Rheinland refinery, Germany’s largest.

Shell previously attempted to shed its interest in the Schwedt refinery in late 2016 to Varo Energy BV.

Gazprom Neft lets contract for new unit at Moscow refinery

PJSC Gazprom Neft subsidiary JSC Gazpromneft-MNPZ has let a preliminary contract to Técnicas Reunidas SA to provide engineering, procurement (EP) as well as project management services on construction of a grassroots delayed coking unit to be built as part of a new deep refining complex planned under the operator’s ongoing modernization and upgrade of its 12-million tonne/year Moscow refinery.

Técnicas Reunidas will carry out EP and oversee equipment deliveries, construction, and commissioning activities for a new 2.4-million tpy delayed coker designed to process residual oil into high-quality clean fuels, the service provider and Gazprom Neft said.

Valued at $240 million, the contract will run a total of 40 months for a scheduled project completion in 2025, according to Técnicas Reunidas.

The new delayed coker forms part of Gazpromneft-MNPZ’s construction of a deep refining complex that also will include a new hydrocracking plant on which DL E&C Co. Ltd. of South Korea and its subsidiary Daelim RUS LLC will deliver EP services (OGJ Online, Mar. 12, 2021).

Initiated in 2011 and scheduled for completion in 2025 at a final estimated cost of 350 billion rubles, the Moscow refinery’s modernization program has included various initiatives allowing the refinery to reduce its premodernization environmental impacts by 50%, with anticipation of another 50% reduction in impacts to occur once all Phase 2 works are completed in 2021 (OGJ Online, Mar. 27, 2020).

Raízen lets additional contract for Buenos Aires refinery

Raízen Argentina SA—a subsidiary of Royal Dutch Shell PLC and Cosan SA 50-50 joint venture Raízen Energia SA—has let a contract to KBR Inc. to supply engineering and technology services for a new unit to be installed at the operator’s 108,000-b/d refinery at Dock Sud in Avellaneda County, Buenos Aires Province, Argentina.

As part of the contract, KBR will deliver a basic engineering package as well as reaction and catalyst regeneration technologies for the refinery’s new FCC configuration project to enable the operator to achieve higher unit profitability, enhanced on-stream availability, and a reduced carbon footprint, the service provider said on June 28.

KBR disclosed no further details regarding the specific technologies or unit specifications involved under the agreement.

This most recent contract follows Raízen Argentina’s earlier June contract award to Axens Group for delivery of a modular 10,200-b/sd FCC gasoline hydrodesulfurization unit outfitted with Prime-G+ process technology that will enable the refinery to upgrade the quality of its gasoline pool production to comply with more stringent Euro 5-quality fuel specifications in Argentina taking effect on Jan. 1, 2024.

The new modular FCC gasoline hydrodesulfurization unit is one of several projects included under Raízen Argentina’s $715-million investment program to modernize and expand operations at the Buenos Aires refinery during the 2020-23 period that will include works to increase the refinery’s processing capacity, upgrade existing units and processes, as well as improve energy efficiency and environmental practices.

In late March, the government of Argentina said Raízen Argentina was advancing development of $71-million worth of new units for the refinery under the 2020-23 program, including construction of a new naphtha hydrotreater, diesel hydrotreater, hydrogen production plant, and water treatment plant.

The spending program also includes plans for installation of a new crude distillation column at the site.

Information regarding the precise scope of the refinery’s FCC unit configuration project, however, have yet to be confirmed by the operator.


Dominion, Berkshire Hathaway terminate pipeline agreement

Dominion Energy is beginning a competitive process for the sale of Questar Pipelines with a target close of yearend 2021 after a deal to sell the pipeline group to Berkshire Hathaway Energy was terminated due to ongoing uncertainty associated with achieving clearance from the Federal Trade Commission, Dominion said in a July 12 release.

The development has no impact on the sale of gas transmission and storage assets to Berkshire Hathaway Energy completed in November 2020, Dominion said.

Dominion Energy will continue to account for Questar Pipelines as discontinued operations and intends to enter a 364-day term loan to repay the $1.3 billion transaction deposit made by Berkshire Hathaway. The loan is expected to be repaid by yearend 2021 with proceeds from the sale of Questar Pipelines to an alternative buyer.

Gastrade Greek LNG terminal gets EC funding approval

Gastrade SA, a joint venture of Public Gas Corp. of Greece AE (DEPA) and Bulgarian gas transmission system operator Bulgartransgaz EAD, has received European Commission (EC) approval of €166.7 million ($199 million) in government aid for construction of a new 5.5-billion cu m/year (bcmy) LNG terminal 10 km offshore Alexandroupolis, Greece. The terminal project will consist of a floating storage and regasification unit, mooring system, risers, and 4-km subsea and 24-km onshore gas pipelines to connect it with the Kipi‐Komotini branch of the National Natural Gas System of Greece.

The EC described the project, to be completed by 2023, as “contributing to the security and diversification of energy supplies in Greece and southeast Europe without unduly distorting competition” in designating it a European Project of Common Interest. Links are planned for shipment of gas from the terminal via the NNGS to the Greece-Bulgaria Interconnector (IGB) pipeline, currently under construction.

IGB construction will be complete by December 2021, with commissioning of the 3-bcmy line expected no later than July 2022. The 182-km pipeline will be expandable to 5 bcmy. Half of its initial capacity is already booked, 1 bcmy by Bulgargaz EAD from the Shah Deniz 2 project in the Caspian Sea.

Greek authorities have confirmed the LNG terminal would also be suitable for hydrogen use. Greece will finance the project using European Structural and Investment Funds.

Symbio lets contract for Saguenay LNG, pipeline engineering

Symbio Infrastructure LP and Siemens Energy have entered into an agreement for Siemens to provide engineering services, comprehensive lifecycle equipment and technology solutions, and further carbon emission footprint reduction solutions for Symbio subsidiary GNL Quebec’s 10.5-million tonne/year Énergie Saguenay LNG plant in Quebec and subsidiary Gazoduq’s natural gas transmission pipeline between northeastern Ontario and Saguenay.

Énergie Saguenay, expected to be operational in 2026, will be powered by nearby hydroelectricity. Fed by Gazoduq’s carbon-neutral transmission line, Symbio said it expects Énergie Saguenay to be the lowest carbon-intensity LNG plant in the world.

Gazoduq is conducting information and consultation meetings with local communities and indigenous groups along its 780-km route. It will next begin regulatory filings with the Impact Assessment Agency of Canada, the Canada Energy Regulator, and the Ministry of Sustainable Development, Environment, and Fight Against Climate Change. Symbio plans to place it in service to coincide with Saguenay’s startup.

Siemens will provide what it describes as greener solutions for rotating equipment, electrical, and digital infrastructure. Symbio and Siemens will also work together to explore green hydrogen development opportunities.