OGJ Newsletter

Oct. 19, 2020


Equinor continues Hammerfest LNG fire investigation  

Equinor has started an internal investigation into the fire at the Hammerfest LNG facility on Melkoya Island in northern Norway on Sept. 28 and is looking into findings pointed out by the Petroleum Safety Authority (PSA) in a recent inspection (OGJ Online, Sept. 28, 2020).

Both the PSA and Equinor are investigating the incident to clarify the course of events and to find triggering and underlying causes and the police is also investigating the incident.

Equinor had initiated an investigation of a gas leak that occurred roughly 2 weeks prior to the fire, Equinor said Oct. 2. The operator said while there is no indication of a connection, it will investigate whether the fire can in any way be related to the leak. The investigation also will seek to clarify if a Sept. 28 power outage in Hammerfest was related to the fire.

Equinor has established a separate project to assess the condition of the plant and take measures to ensure a safe start-up in due course. No timeline was given.

“We are now working to map the extent of damages after the fire and will then thoroughly review the technical integrity of the facility. Safety comes first, and we will use the time we need to ensure a safe start-up. It is still too early to say when the operations can resume,” said Irene Rummelhoff, executive vice-president of marketing, midstream, and processing at Equinor.

In the week before the incident, the PSA carried out an inspection of electric systems and major accident preparedness at the facility, and on Sept. 24, the PSA verbally shared a first summary after the inspection. The PSA said it had observed that some items had not been satisfactorily followed up by Equinor since the same type of audit was last carried out in 2017, and that incorrect registrations have been made in the system used for follow up.

“Equinor takes the PSA’s feedback seriously and has already started examining the basis for the findings to address pending items while we wait for the PSA’s final report from the inspection. We will also evaluate whether the findings are isolated cases or if there is a need to address routines and systems,” Rummelhoff said.

Pandion, ConocoPhillips swap license interests offshore Norway 

Pandion Energy AS has entered into an agreement with ConocoPhillips Skandinavia AS to swap half of its 20% interest in North Sea license PL 1047 in exchange for ConocoPhillips’ 20% interest in PL 938 containing the Calypso prospect in the Norwegian Sea. PL 938 lies in the Haltenbanken area in Block 6407/8, just north of Bauge and Hyme fields.

PL 938 was awarded in the 2017 APA round and is operated by Neptune Energy Norge AS (60%) with ConocoPhillips (20% before swap) and Vår Energi AS (20%) as partners. Drilling of an exploration well is planned in 2021 or 2022.

PL 1047 is operated by Aker BP ASA (40%) with Concedo ASA (20%), ConocoPhillips (20% before swap), and Pandion Energy (20% before swap) as partners. The license is adjacent to Martin Linge field.

With the deal, Pandion commits to its fourth exploration well in the Norwegian Sea, said Jan Christian Ellefsen, chief executive officer. “Together with ongoing and planned wells in PL 263 D & E (Appolonia), PL 891 (Slagugle) and PL 929 (Ofelia), we now have a portfolio of four exploration wells, all close to existing infrastructure,” he said.

The transaction is subject to customary conditions, including approval by the Norwegian Ministry of Petroleum and Energy.

In September, OKEA ASA agreed to acquire a 30% interest in PL 938 from Neptune Energy Norge AS. Neptune will retain a 30% interest and remain operator of the license.

Exploration & Development Quick Takes 

Neptune Energy begins Seagull subsea construction  

Neptune Energy has commenced the subsea construction phase of its Seagull tieback project in the central North Sea (OGJ Online, Mar. 28, 2019).

TechnipFMC, working under the Neptune Energy Alliance Agreement, deployed the Apache II pipelay vessel to start the pipe-in-pipe installation, laying some 5 km of pipe connecting the Egret manifold to the Seagull development.

Seagull, a high pressure, high temperature (HPHT) development on UK license P1622 Block 22/29C, 17 km south of the BP-operated ETAP central processing facility, is expected to produce 50,000 boe/d (gross). Proved plus probable gross reserves are estimated at 50 million boe.

TechnipFMC’s Normand Mermaid was mobilized late-August to provide pre-lay activities, including surveying and boulder removal. Following the pipe installation, its Normand Ranger will undertake trenching activities.

The development will be tied back to the ETAP Central Processing Facility, partially utilizing existing subsea infrastructure. Gas from the development will come onshore at the CATS processing terminal at Teesside, while oil will come onshore through the Forties Pipeline System to the Kinneil Terminal, Grangemouth, Scotland.

Neptune is operator of Seagull with 35% equity interest. Joint venture partners are BP 50% and JAPEX 15%.

Equinor discovers oil in North Sea Swisher prospect 

Equinor and partners will evaluate an oil and gas discovery in the Swisher prospect in the North Sea for a potential tie-in to existing infrastructure in the area. Wells 35/11-24 S, 35/11-24 A, and 35/11-24 B were drilled in production license 248C about 7 km west of Fram field and 130 km northwest of Bergen in 356 m water depth. Recoverable resources are estimated at 2-6 million standard cu m oil equivalent, corresponding to 13-38 MMboe.

The wells—the third, fourth, and fifth in the license—were drilled by the West Hercules drilling rig to prove petroleum in Upper Jurassic rocks of the Heather formation from the Late Jurassic epoch. Well 35/11-24 S was drilled to 3,082 m TVD and 3,200 MD subsea and encountered a 42 m hydrocarbon column including 21 m of gas with 7 m moderate to good reservoir quality and 21 m of oil with 17 m of good to moderate reservoir quality.

Well 35/11-24 A was drilled to 3,213 TVD and 3,549 MD subsea and encountered a 25 m total gas column and up to 6 m moderate quality sandstone. Well 35/11-24 B was drilled to 3,088 TVD and 3,480 MD subsea and encountered a 3 m minimum oil column of good-quality sandstone.

The wells were not formation-tested, however extensive data acquisition and sampling were carried out.

The wells have been permanently plugged. West Hercules will proceed to drill wildcat well 6407/1-8 S in the Apollonia prospect in production license 263 D in the Norwegian Sea.

Equinor is operator of 248C (35%) with partners Petoro AS (40%), and Wellesley Petroleum AS (25%).

Wintershall Noordzee develops third Sillimanite well 

Wintershall Noordzee BV, a 50-50 joint venture of Wintershall Dea GmbH and Gazprom EP International BV, drilled the Sillimanite South field discovery well in the North Sea and directly converted it into a development sidetrack.

It is the third well drilled in sequence after the two Sillimanite Unit field development wells were successfully brought into production earlier this year (OGJ Online, June 16, 2020). The JV is finalizing hook-up activities to the D12-B production platform situated close to the Anglo-Dutch border in Dutch territorial waters. From there, the produced gas will be transported via the Neptune-operated D15-A production platform, through the NGT gas transportation system to shore.

The unitized Sillimanite gas field, discovered in 2015, lies about 200 km off the coast of Den Helder on the maritime border of the Netherlands and the United Kingdom in license Block 44/19a on the UK side and Blocks D12a and D12b on the Dutch side. The Sillimanite South prospect lies entirely in Block D12a. An agreement was reached in 2018 to allow for development to proceed. Production begin early this year (OGJ Online, Feb. 20, 2020).

Both Sillimanite and Sillimanite South gas fields are producing from sandstone reservoirs of Carboniferous age at a depth of 3,700 m subsea.

Wintershall Noordzee BV operates the Sillimanite South joint venture with 39.5%. Partners are EBN BV 50% and Neptune Energy 10.5%.

Drilling & Production Quick Takes 

BP starts production at Oman’s Ghazeer gas field 

BP began production from Oman’s Ghazeer gas field, 33 months after development approval. Ghazeer, Phase 2 of Block 61 development, was initially expected to come into production in 2021.

Hydrocarbons produced during testing and completion were routed to the production facility instead of flared. Since adopting this approach in 2019, 201,000 tonnes of CO2e emissions were saved, equivalent to removing 44,000 cars from the road for a year, BP said.

Total production capacity from Block 61, comprising both Khazzan and Ghazeer, is expected to rise to 1.5 bcfd and more than 65,000 b/d of associated condensate. Phase 1 development, Khazzan, was brought online in September 2017 (OGJ Online, Sept. 25, 2017). With an estimated 10.5 tcf of recoverable gas resources, the block has the capacity to deliver about 35% of Oman’s total gas demand. 

BP is operator in Block 61 (60%) with partners Makarim Gas Development Ltd. (OQ, 30%), and Petronas’s PC Oman Ventures Ltd. (10%).

Equinor issues LOI for Breidablikk drilling  

Equinor issued a letter of intent (LOI) to Odfjell Drilling and the Deepsea Aberdeen rig for 15 Breidablikk oil field wells in the Norwegian Continental Shelf (NCS), northeast of Grane field in the North Sea.

The agreement includes options for drilling an additional nine wells before continuous optionality apply. Drilling is scheduled to start in the spring of 2022, and the campaign is estimated to last until the autumn of 2024.

At end September, the partners submitted a plan for development and operation (PDO) for Breidablikk. The field will be developed with four subsea templates, each with six slots. The templates will be tied into and controlled from the Grane platform. The plan calls for 23 production wells, and oil will be processed and exported via Grane to the Sture terminal in Hordaland county (OGJ Online, Sept. 28, 2020). Production from Grane will be monitored with advanced digital tools from Equinor’s integrated operations center at Sandsli.

The estimated value of the fixed part of the agreement is $290 million. Additional costs include integrated services, maintenance, modifications, mobilization, and demobilization.

Estimated field recovery is around 200 million bbl with an investment of 18.6 billion kroner.

Equinor operates Breidablikk (previously Grand) in license 169 B2 with 47.5%. Partners are Petoro AS 30%, Vår Energi 10%, and ConocoPhilips Skandinavia AS 12.5%.

Serica Energy preps Rhum R3 for production 

Serica Energy PLC began offshore operations to prepare the Rhum R3 well for production. The well, in Rhum field, 380 km northeast of Aberdeen in 109 m of water, requires intervention work.

Awilco Drilling’s WilPhoenix semi-submersible drilling rig is installed over the well and will recover equipment left in the well by the previous operator and remove an obstruction in place across parts of the downhole completion. The well will then be recompleted. Rig operations are expected to last about 70 days.

The gas condensate field produces from two subsea wells, R1 and R2, tied into Bruce facilities through a 44 km pipeline. Production is predominantly gas and exported to St Fergus for delivery into the National Transmission System. Small quantities of associate condensate are exported onshore via the Forties Pipeline System. The field has produced at a relatively constant rate of 13,775 boe/d net to Serica through the past year.

Successful recompletion of R3 will increase the production capacity using existing production facilities on the Bruce platform and will, therefore, not lead to any significant additional CO2 emissions. R3 is already connected to the subsea production infrastructure and is expected to start production early 2021.

Serica is operator at Rhum (50%) with partner National Iranian Oil Co. (NIOC, 50%).


Qatar Petroleum’s Mesaieed refinery begins ULSD production 

Qatar Petroleum (QP) has completed a project enabling production of ultralow-sulfur diesel (ULSD) at its 137,000-b/d refinery in Mesaieed Industrial City (MIC), about 40 km south of Doha, Qatar.

The MIC refinery began supply of ULSD to Qatar’s domestic transportation market on Sept. 27, ensuring all diesel now sold in the country meets the Euro 5-quality emission standard of maximum 10 ppm sulfur, QP said in a release.

Start of ULSD production at the MIC refinery follows QP’s completion of an upgrading project at the site’s diesel hydrotreating units, the operator said.

QP said the refinery’s production of Euro 5-quality ULSD marks an important step and forms an integral part of QP’s goal of maximizing value of Qatar’s downstream businesses and delivering on the company’s commitment to protect and enhance the environment.

While the operator disclosed no further details regarding the MIC refinery’s upgrade of its diesel hydrotreaters, QP previously confirmed it completed preliminary front-end engineering design activities for a proposed upgrading project at the refinery in 2018 (OGJ Online, Apr. 22, 2020).

Designed to improve the refinery’s gasoline production to Euro 5-quality specifications from Euro 3 standards, the planned upgrading project was to involve installation of a new residue fluid catalytic cracker (RFCC) and light-gasoline hydrotreating unit, both of which were due to be completed by early 2020.

The MIC refinery processes a feedstock consisting mainly of crude oil and condensate from Dukhan field, as well as condensate from North field.

RusGazDobycha lets additional contract for Ust-Luga chemical complex 

JSC RusGazDobycha subsidiary Baltic Chemical Complex LLC, through a subcontractor, has let a contract to PESCO Switzerland AG to provide project management (PM) for its $13-billion ethane cracking project under construction on the Gulf of Finland near Ust-Luga, Russia (OGJ Online, Nov. 18, 2019; Apr. 2, 2019).

As part of the contract awarded by China National Chemical Engineering & Construction Corp. Seven Ltd. (CC7), PESCO Switzerland will deliver PM services for early works, long-lead item (LLI) procurement, and supply for the project, the service provider said.

While it did not disclose a value of the PM contract, PESCO Switzerland said this latest award follows a previous contract to PESCO Switzerland in November 2019 to provide PM services for the project’s extended basic engineering stage as part of jointly integrated PM team with CC7.

First announced in 2019 and slated to become the largest ethylene integration project in the world once completed, the natural gas processing chemical plant will include two ethylene cracking sites—each with a capacity of 1.4 million tonnes/year—six polyethylene trains with a combined processing capacity of 480,000 tpy, and two linear alpha olefin plants with a combined capacity of 137,000 tpy.

Construction work on the integrated complex—which will process ethane-containing gas from PJSC Gazprom’s production fields—currently is proceeding according to schedule (OGJ Online, Sept. 18, 2020).

The complex is due to be completed in two phases, with Phase 1 commissioning planned for fourth-quarter 2023 and Phase 2 startup to follow in fourth-quarter 2024, according to RusGazDobycha.

Shurtan GCC lets contract for ethylene expansion

JSC Uzbekneftegaz subsidiary Shurtan Gas Chemical Complex LLC (Shurtan GCC), through a subcontractor, has let a contract to Lummus Technology LLC to deliver technology licensing and equipment for a project that will more than double ethylene production at Shurtan GCC’s petrochemical complex in the Guzar district of southern Uzbekistan’s Kashkadarya region.

As part of the contract awarded by subcontractor Enter Engineering Pte. Ltd., Lummus will design and supply four proprietary Short Residence Time (SRT) VI and SRT VII cracking furnaces, the service provider said.

Lummus disclosed no further details regarding either a value of the contract or its timeframe for work on the project.

Previously scheduled to be completed during second-half 2020, Shurtan GCC’s proposed expansion was to increase the complex’s polyethylene production capacity to 450,000 tpy from its current 125,00-tonnes/year (OGJ Online, June 29, 2017).

Financed by a mix of funds from Uzbekneftegaz, Shurtan GCC, and loans from Chinese and Russian financial institutions and banks, the expansion comes as part of a May 11, 2017, decree of the President of the Republic of Uzbekistan designed to ensure Shurtan GCC’s complex further diversify its polymer production, improve its technical and economic indexes, increase export potential, and reduce imports of raw materials by increasing production of high-quality products in demand in foreign and local markets, according to Shurtan GCC’s website.

As of 2019, construction on the project—for which Shurtan GCC previously awarded a turnkey $1.3-billion contract to Enter Engineering to provide engineering, procurement, and construction—was under way, Shurtan GCC said.

Detailed design and project development were carried out by specialists from Uzbekneftegaz, Uzbekistan GTL LLC, Hyundai Engineering & Construction Co. Ltd., McDermott International Inc., and Enter Engineering, according to the operator.


Magnolia LNG gets 5-year FERC permit extension 

Glenfarne Group LLC’s recently acquired 8.8-million tonne/year (tpy) Magnolia LNG export terminal development project in Lake Charles, La., has received a 5-year permit extension from the US Federal Energy Regulatory Commission (FERC), allowing it to begin operations as late as Apr. 15, 2026. The extension also applies to the 1.4-bcfd Lake Charles Expansion of the Kinder Morgan Louisiana Pipeline (KMLP).

The companies had cited “unforeseeable developments” in the global LNG market in requesting the extension (OGJ Online, Sept. 16, 2020).

Magnolia LNG will include four 2.2-million tpy trains using patented optimized single-mixed refrigerant (OSMR) liquefaction technology. Magnolia LNG is already permitted to receive natural gas through the 2-bcfd KMLP.

Glenfarne also owns the 4-million tpy Texas LNG project, under development in Brownsville, Tex. The company bought Magnolia LNG earlier this year (OGJ Online, June 10, 2020).

Pieridae awards Goldboro LNG services agreement to Bechtel 

Pieridae Energy Ltd. signed a services agreement with Bechtel Corp. to develop an engineering, procurement, construction, and commissioning (EPCC) plan for Pieridae’s two-train 10 million tonne/year (tpy) Goldboro LNG plant in Nova Scotia, Canada. The plan is to be completed by Mar. 31, 2021.

Other key deliverables in the services agreement include:

  • Initiating a detailed review of the scope and design of Goldboro LNG.
  • Delivering a final lump-sum, turnkey EPCC contract price proposal by May 31, 2021.
  • Engaging the Nova Scotia Mi’kmaq First Nations, including their participation in building a large-scale work camp at the construction site.

Kellogg Brown & Root Ltd. (KBR) gave Pieridae written notice earlier this year that it was no longer prepared to negotiate and conclude a lump-sum turnkey EPCC contract in relation to Goldboro LNG. The move followed KBR’s announcement that it would be exiting lump-sum engineering, procurement, and construction (EPC) work, a move hastened by the coronavirus pandemic (OGJ Online, July 14, 2020).

Bechtel earlier this year signed a fixed-price EPC contract for Sempra Energy’s 13.5-million tpy Port Arthur LNG plant in Port Arthur, Tex. (OGJ Online, Mar. 3, 2020).

TransAlta sells Pioneer gas pipeline 

TransAlta Corp., with its partner Tidewater Midstream & Infrastructure Ltd., has sold the 131-km Pioneer Pipeline to ATCO Gas and Pipelines Ltd. Pioneer will be integrated into Nova Gas Transmission Ltd.’s (NGTL) and ATCO’s Alberta natural gas transmission systems to supply TransAlta’s powerplants at Sundance and Keephills.

As part of this transaction, TransAlta entered into additional long-term transportation agreements with NGTL for a total of new and existing transportation service of 400 MMcfd by 2023. TransAlta’s current commitments, including 139 MMcfd with Tidewater, remain in place until closing of the transaction.

This deal replaces TransAlta’s previous agreement to sell its interest in Pioneer Pipeline to NGTL (OGJ Online, Mar. 12, 2020). ATCO acquired the right to purchase the Pioneer Pipeline through an option agreement with NGTL and paid CDN $255 million ($192 million).

The transaction is subject to customary regulatory approvals which are anticipated by second-quarter 2021.