OGJ Newsletter

Jan. 10, 2022


Energy prices rose more than other commodities in 2021

Energy prices used in the S&P Goldman Sachs Commodity Index (GSCI) ended 2021 59% higher than the first trading day of the year, according to an analysis from the US Energy Information Administration.

Energy price increases were mainly due to increased demand from the initial stages of global economic recovery from the COVID-19 pandemic. By comparison, most other commodity indexes included in the GSCI rose by about 20%. The precious metals index was the only one that fell. The energy index of the GSCI increased more than twice as much as the industrial metals index on a percentage basis during 2021, the second highest commodity index group price change.

The GSCI is a commodity index that tracks the performance of global commodities markets. The index is a weighted average of commodity prices, and the index updates the weight it allocates to each commodity every year. In 2021, the energy index group made up 54% of the GSCI, and two crude oil benchmarks, WTI and Brent crude oil, accounted for approximately 70% of the weighting in the energy sector index. WTI crude oil makes up the largest share of the overall GSCI at more than 21%.

Prices in energy commodity futures markets greatly increased throughout 2021. For example, the futures price of RBOB (a reformulated grade of gasoline used as the benchmark for gasoline trading) increased by 67% during 2021. The only commodity included in the GSCI that increased more was coffee, whose futures price increased by 81% during 2021.

Among energy commodities, prices for petroleum products such as RBOB and ULSD (ultra-low sulfur diesel, which is used as a benchmark for heating oil trading) increased the most during 2021, at 67% and 64%, respectively. Prices for crude oils such as WTI (62%) and Brent (55%) increased by slightly less. Futures prices for gasoil (the name for ULSD in Europe) increased by 54% during 2021. Natural gas prices increased the least among energy commodities, although 38% is still a relatively large increase.

OPEC+ to raise output target by 400,000 b/d for February

In the Ministerial Meeting Jan. 4, OPEC and its non-OPEC allies (OPEC+), reaffirmed the planned increase in oil output for February. According to the agreement reached in July last year, the current plan is for OPEC+ to raise the February target by 400,000 b/d.

The move has been expected by the market, given the pressure from the US to boost supply and the absence of new major COVID-19 restrictions.

According to a recent report from the Joint Technical Committee, OPEC+ expects the Omicron variant to have a “moderate and short-lived” impact on global energy demand and is optimistic about the economic outlook.

Brent prices have recovered close to $80/bbl after falling below $70/bbl in early December. Real-time transportation data globally suggests no significant impact on oil demand thus far from Omicron.

“What matters to the market and prices at the moment is the global picture, so we may see more action when we have more clarity over global production in the coming months. Ongoing outages in Libya, struggling production recovery in Nigeria, and reduced expectations for Russian production capacity add bullish weight to the scale from the supply side,” said Bjørnar Tonhaugen, Head of Oil Markets at Rystad Energy.

“All the while, for now the Omicron risk remains exactly that, a risk. Instead of an outright deeper lockdown impact, market balances will remain somewhat tight for January and February and keep oil prices supported, especially with supply side concerns and a disciplined OPEC+,” said Tonhaugen.

However, “it will be key for the month’s price volatility to watch whether OPEC+ ministers will opt to keep the meeting ‘in session’ and leave the door open to reconvene before the February meeting to revise the decision based on market conditions, mirroring the unorthodox but tactical move introduced at the previous get-together.”

Australian Government blocks renewal of offshore Sydney permit

The Australian Government has said there will be no petroleum exploration off the New South Wales coast, blocking plans for a well proposed in the region by a joint venture headed by Perth-based Advent Energy Ltd. Prime Minister Scott Morrison made the announcement while in the area, saying the government was taking steps to protect local communities and the environment by blocking the renewal of offshore permit PEP 11, offshore between Sydney and Newcastle.

The permit expired in February 2021 and the Advent Energy JV has been waiting 10 months for federal and New South Wales state authorities to approve its renewal application so it could begin its proposed drilling program. The JV had planned to drill wildcat well Seablue-1 in 125m of water, 26 km off the coast.

Advent, owned by three companies (BPH Energy Ltd., MEC Resources Ltd., and Grandbridge Ltd.), said it had yet to receive official notification of refusal to renew the permit from the National Offshore Petroleum Title Authority (NOPTA) and would make no comment until then. Once the notification is given, NOPTA will grant the JV 30 days in which to respond. But it seems clear the drilling will not take place. Prime Minister Morrison said that the drilling project will not proceed “on our watch.”

“Gas is an important part of Australia’s current and future energy mix, but this is not the right project for these (coastal NSW) communities and pristine beaches and waters,” he said.

The offshore sector of the Sydney basin has been a controversial destination for a number of decades because of its close proximity to large populations and a pristine coastline. Although some seismic surveys have been run and several prospects with mid-Permian targets delineated, no drilling has occurred. The prospects are thought to be gas prone.

Historically the offshore sector has been covered by a single permit, PEP 11, covering about 4,580 sq km. Permit holders hoping for renewal are Advent, with 85%, and Bounty Oil and Gas NL, 15%.

QatarEnergy enters Egypt offshore exploration

QatarEnergy will enter Egypt’s upstream oil and gas sector through an agreement to acquire working interests in two offshore exploration blocks from Shell Exploration & Production (93) BV, a subsidiary of Royal Dutch Shell PLC.

Under the terms of the agreements, QatarEnergy will hold a 17% working interest in Red Sea Blocks 3 and 4. Shell will remain operator of both blocks.

Block 3 was awarded to Shell in late 2019 and covers an area of 3,097 sq km in water depths of 100-1,000 m. Block-4 was also awarded to Shell in late 2019 and covers an area of 3,084 sq km in water depths of 150-500 m.

Upon closing of the agreements, subject to customary approvals by the government of Egypt, working interests in the two blocks will be: Block 3: Shell (43%), BHP (30%), Tharwa Petroleum Co. (10%), and QatarEnergy (17%); Block 4: Shell (21%), Mubadala (27%), BHP (25%), Tharwa Petroleum Co. (10%), and QatarEnergy (17%).

 Exploration & Development Quick Takes

CGX discovers active hydrocarbon system in Corentyne block, offshore Guyana

CGX Energy Inc. discovered hydrocarbons in the Kawa-1 exploration well in the Corentyne block, offshore Guyana. The well lies in the northeast quadrant of the block, about 200 km offshore Georgetown. Water depth is about 355 m and the expected total depth of the well is 6,685 m.

To date, about 90% of the planned footage has been drilled and initial results suggest an active hydrocarbon system is present at Horizon 19, the first of three targeted geological zones. Logging-while-drilling and cuttings indicate the presence of hydrocarbons in several Campanian and upper Santonian formations. The 9 5/8-in. liner will be run at current depth, then the well will be drilled ahead to the main Santonian target zone (Horizon 23) and the deeper secondary Santonian target zone (Horizon 25). Initial geological results will be further evaluated by wireline logging at the end of the well as part of the logging program for the deeper zones.

Drilling has taken longer than originally forecast and costs are projected to increase to about $115-125 million. The joint venture will provide an update on costs and issue full exploration results of the well once total depth has been reached and results have been analyzed.

Frontera Energy Corp. is CGX’s joint venture partner in the 1.125-million net acre block.

Petrobras plans Sergipe-Alagoas basin development

Petróleo Brasileiro SA (Petrobras), operator of BM-SEAL-4 and BM-SEAL-11, and sole owner of BM-SEAL-4A and BM-SEAL-10 concessions rights, submitted declarations of commerciality of the areas to the National Agency of Petroleum, Natural Gas and Biofuels (ANP).

In the declarations, Petrobras suggested field names Budião, Budião Noroeste, Budião Sudeste, Palombeta, Cavala, Agulhinha, and Agulhinha Oeste. Petrobras intends to develop the fields in two modules—Sergipe Deepwater (SEAP) I and II, which foresee the installation of two FPSO-type platforms.

The first platform, planned to serve the SEAP I module, will be the P-81, scheduled to start production in 2026, with capacity to produce 120,000 bbl of oil/condensate and flow 8 million cu m/d of gas. The second platform, planned to serve the SEAP II module, is in the contracting planning phase and is scheduled to start production after the company’s 2022-2026 strategic plan horizon.

The SEAP I and II modules include the implementation of a new gas flow system connecting the two production modules to the Sergipan coast, with a capacity of 18 million cu m/d.

Petrobras is operator of BM-SEAL-4A and BM-SEAL-10 concessions with 100% interest, in BM-SEAL-11 concession with 60%, in partnership with IBV Brasil Petróleo Ltda. (40%), and in BMSEAL-4 concession with 75%, in partnership with ONGC Campos Ltda. (25%).

Energean lets additional Karish FPSO oil train contract

Energean PLC has let an engineering, procurement, and construction contract (EPC) to KANFA AS for a second oil train on the Energean Power FPSO tying back Karish and Karish North fields, offshore Israel.

KANFA will provide project management, engineering, procurement, fabrication, and precommissioning work for the fully assembled new module. The module comprises a second oil separation train and a flash gas compressor package designed to operate in conjunction with existing FPSO processing systems.

The new three-deck structure weighs about 700 tonnes. Following completion, the topside module will be transported to Karish field for integration onto the vessel, requiring a ship-to-ship heavy lift operation scheduled to take place third-quarter 2023.

The new oil-condensate separation module will increase the FPSO’s liquid production capacity to 32,000 b/d from 18,000 b/d. The brownfield project will enable Energean to meet increased gas production from 2023 onwards from the fields, both of which have shown high liquid-gas ratios. Increasing FPSO hydrocarbon liquid treatment capacity by 75% will enable a more balanced distribution of offtake per well over the life of the fields, enhancing ultimate recovery, the company said.

An early 2022 offshore Israel exploration and appraisal drilling program will drill five wells including appraisal of the potential oil rim that was identified as part of the Karish development drilling campaign plus exploration of further prospective gas and liquids volumes within the Karish lease.

 Drilling & Production Quick Takes

Norway production decreased in November, NPD says

Norway’s liquids production averaged 1.999 million b/d in November, the Norwegian Petroleum Directorate reported Dec. 21.

Norway’s liquids production averaged 2.062 million b/d in October (OGJ Online, Nov. 19, 2021).

Oil production in November is 5.0% lower than the NPD’s forecast, and 0.5% higher than the forecast so far 2021.

The average daily liquids production in November consists of 1.729 million b/o, 257,000 bbl of NGL, and 13,000 bbl of condensate.

Total petroleum production so far in 2021 is about 210.8 million standard cu m oil equivalents.

The total volume is 2.8 higher than the 2020-figures.

VAALCO begins Etame drilling campaign

VAALCO Energy Inc. has spudded the Etame 8H-ST well, starting its 2021-2022 drilling campaign offshore Gabon.

The well, the first in a four well campaign, will be drilled by a jack up rig provided by Borr Drilling Ltd. which has recently been deployed to the Etame platform (OGJ Online, June 16, 2021). The sidetrack is targeting existing Gamba hydrocarbons in Etame field that have not previously been produced by prior wells.

Drilling is expected to be completed in January with production expected later in first-quarter 2022.

The Etame Marin block is in the Congo basin about 32 km off the coast of Gabon. The license area is spread over five fields covering a total area of about 187 sq km. VAALCO is operator in Etame Marin field (63.6%) with partners Addax Petroleum Co. (33.9%) and PetroEnergy Resources Corp. (2.5%).

CNOOC starts production at Bohai Sea

CNOOC Ltd. has started production at the Caofeidian 11-6 oilfield expansion project and Kenli 16-1 oilfield.

The Caofeidian 11-6 oilfield expansion project lies in west Bohai Sea, with average water depth of 23 m. A new unmanned wellhead platform was built, and existing processing infrastructure is used. A total of 9 development wells are planned, including 7 production wells and 2 water injection wells. The project is expected to reach peak production of about 4,600 b/d of crude oil in 2022.

Kenli 16-1 oilfield lies in south Bohai Sea in average water depth of about 15 m. A new wellhead platform was built, and existing processing infrastructure is used. A total of 23 development wells are planned, including 16 production wells and 7 water injection wells. The field is expected to reach peak production of 7,500 b/d of crude oil in 2022.

SDX to tie in first well in West Gharib development campaign

SDX Energy PLC will tie in hydrocarbons from the MSD-21 infill development well on Meseda field in the West Gharib concession in the Egyptian Eastern Desert adjacent to the Gulf of Suez.

MSD-21 encountered the primary top Asl Formation reservoir at 4,040 ft MD and reached a TD of 4,740 ft. The well encountered 62.3 ft of good-quality, net oil pay sandstone, with an average porosity of 21.3% in the Asl Formation reservoir. MSD-21 will now be tied-in to existing facilities and flow tested.

The well is the first in a 12-well development campaign on Meseda and Rabul oil fields within block H of the West Gharib concession. The fields have 100 MMbbl in place and the development drilling campaign is aimed at growing production to about 3,500-4,000 b/d by early 2023 from current rates of about 2,400 b/d (OGJ Online, Oct. 18, 2021).

The rig will now move to the next well in the campaign, MSD-25, which is expected to spud in early to mid-January 2022.

SDX holds a 50% working interest in the license. Partners are The General Petroleum Co., a wholly owned subsidiary of the Egyptian General Petroleum Corp., and Dublin Petroleum Ltd.

Santos JV to drill Dorado satellite prospects in January

The Santos Ltd.-Carnarvon Petroleum Ltd. joint venture in Dorado oil discovery permits WA-437-P and WA-438-P, Bedout sub-basin, offshore Western Australia has announced plans to drill two satellite prospects early in the new year. The Pavo-1 wildcat is scheduled to spud during mid-late January 2022 and the Apus-1 well will follow. The JV has contracted jack up rig Noble Tom Prosser for the two-well program.

Pavo-1, 42 km east of Dorado in 88 m of water, will target the primary Caley to Crespin interval, similar to that intersected in the Dorado discovery. The prospect has estimated potential to hold around 82 million bbl of recoverable liquids and 100 bcf of gas. Following initial drilling, the well will be deepened to acquire geological information on two underlying intervals to provide data regarding Bedout sub-basin’s broader potential.

Pavo-1 drilling is expected to take 2 months before the rig is moved to Apius-1 about 20 km to the southwest. Apus-1, in 84 m of water, will target the Caley and Milne intervals which are similar to those intersected at Dorado. This well is expected to have a drilling time of 1 month. Apus prospect is estimated to potentially hold 235 million bbl of recoverable liquids and 400 bcfd of gas.

Santos has 80% interest and operatorship. Carnarvon has 20%.


HollyFrontier takes down Q4 throughput number

Oil refiner HollyFrontier executives said the company’s crude throughput for the fourth quarter will be about 10% below the estimates provided late 2021.

In a Jan. 3 filing with the US Securities and Exchange Commission, HollyFrontier said throughput should average 420,000 b/d versus the 450,000-470,000 b/d forecast officials provided when discussing the Dallas-based company’s third-quarter results. The drop is the result of both weather and operational factors, including unit downtime at the Puget Sound refinery the company bought last fall from Shell for $614 million, the closure of the Trans Mountain pipeline because of flooding in British Columbia, severe weather and start-up issues at HollyFrontier’s Navajo refinery, and output cuts and severe weather at the company’s refinery in Tulsa.

At 420,000 b/d, HollyFrontier’s fourth quarter volume will be about 1% higher than its throughput from the second and third quarters. In the last 3 months of 2020, the company processed 380,000 b/d.

Parkland restarts operations at Burnaby refinery

Calgary-based Parkland Corp. has restarted processing activities at subsidiary Parkland Refining (BC) Ltd.’s 55,000-b/d refinery on Burrard Inlet in North Burnaby, near North Vancouver, BC, after pausing operations in mid-November amid feedstock supply disruptions caused by a shutdown of the 300,000-b/d Trans Mountain crude oil pipeline.

As of mid-December, the refinery remains in the process of ramping up operations following the Dec. 5 restart of shipments along Trans Mountain, the refinery’s primary source of crude feedstock, Parkland said.

The refinery, which paused operations between Nov. 22-Dec. 10 due to lack of sufficient feedstock, remained in ready mode until Dec. 11, when official ramp-up activities began, according to the operator.

Throughout the temporary halt in crude processing, the Burnaby refinery’s British Columbia terminals remained operational to enable offloading and storage of fuel imports across the lower mainland and Vancouver Island, said Ryan Krogmeier, Parkland’s senior vice-president of supply, trading, and refining.

Parkland did not reveal a specific timeline for when the refinery will return to full operating rates.

The Burnaby refinery processes light and synthetic Canadian crudes such as Edmonton Par 80% and Syncrude 20% delivered via the Trans Mountain pipeline into gasoline, diesel, jet fuel, asphalt, heating fuel, heavy fuel oil, butane, and propane for markets across British Columbia.

PRL advances plan to expand, upgrade Karachi refinery

Pakistan Refinery Ltd. (PRL) has decided to move forward with its long-delayed plan to upgrade and expand its 55,000-b/d hydroskimming refinery along the coastal belt of Karachi, Pakistan.

Approved for development by PRL’s board in a late-December 2021 meeting, the revised plan—now officially known as the refinery expansion and upgrade project (REUP)—will include works to upgrade the site into a deep conversion refinery equipped to produce Euro 5 diesel and gasoline as a means of achieving compliance with the government of Pakistan’s requirement for cleaner, environmentally friendly transportation fuels, the operator said in a filing to Pakistan Stock Exchange Ltd.

Alongside ensuring the refinery’s long-term sustainability by increasing its overall complexity and reducing its output of high-sulfur furnace oil, the REUP also will expand the site’s crude oil processing capacity to 100,000 b/d, PRL said.

Based on an updated detailed feasibility study for the project, PRL estimated REUP will now require a total investment of about $1.2 billion, up from the previous cost estimate of $1 billion in 2019.

PRL—which plans to undertake front-end engineering design (FEED) as well as appoint a financial advisor for REUP by the quarter ending Mar. 31, 2022—said it will take financial investment decision and award a contract for delivery of engineering, procurement, and construction services on the project following completion of the FEED study.

Further details regarding a specific timeframe for REUP were not disclosed.

In its annual report published in mid-August 2021, PRL said it was reviewing options for purchasing preowned refining units with throughput capacities of 50,000-100,000 b/d for relocation to Pakistan as part of its cost-reduction measures for REUP.

In addition to primary bottoms-conversion units, other preowned equipment PRL was considering for purchase included units for hydrotreating, hydrofining, reforming, isomerization, alkylation, hydrogen production, additional sulfur removal, and utilities equipment.


NextDecade delays Rio Grande LNG FID to second-half 2022

NextDecade Corp. has delayed final investment decision (FID) on the 11-million tonne/year (tpy) first phase of its 27-million tpy Rio Grande LNG liquefaction plant in Brownsville, Tex., to second-half 2022. It had been targeting first-half 2022.

The plant has received full permitting for five 5.5-million tpy trains and will include four 180,000-cu m full-containment storage tanks. The workplan for Phase 1 includes full site preparation for the remaining three trains.

Next Decade has contracted Bechtel Corp. to a lump-sum turnkey engineering, procurement, and construction contract and has a 2-million tpy sales agreement in place with Royal Dutch Shell PLC.

Rio Grande LNG will capture and store more than 5 million tpy of carbon dioxide (CCS) at full capacity. It expects to receive US Federal Energy Regulatory Commission approval for the CCS project in 2022 and has contracted Mitsubishi Heavy Industries America Inc. to provide the required technology.

TotalEnergies to build LNG plant in Oman

TotalEnergies SE signed an agreement with the Ministry of Energy and Minerals of the Sultanate of Oman to establish Marsa Liquefied Natural Gas LLC, an integrated company between TotalEnergies (80%) and Oman National Oil Co. (20%). Marsa LNG will produce natural gas from Block 10 of Saih Rawl gas field, about 400 km from Muscat, with a view to subsequently develop a low-carbon LNG plant in Sohar, powered by solar electricity, for production of LNG for bunker fuel.

Marsa LNG will sell natural gas from Block 10 to the government of Oman for 18 years or until start-up of the Marsa LNG plant.

Production from Block 10 is expected to reach about 24,000 boe/d in 2023.

Shell Integrated Gas Oman BV is operator (53.45%) with partners Oman National Oil Co. (13.36%) and Marsa LNG (33.19%).

Mariner East 2 pipeline construction resumes

Sunoco Pipeline, a subsidiary of Energy Transfer LP, has resumed construction of its 20-in. OD, 350-mile Mariner East 2 NGL pipeline in Upper Uwchlan Township, Chester County, Pa. Work will take 5-10 weeks.

The company earlier this month received approval from the Pennsylvania Department of Environmental Protection (DEP) to change the installation method for the 3,184-ft line segment from a horizontal directional drill to an open cut. The modification also changed the pipeline’s route slightly.

This is one of the last sections of the pipeline still to be completed. Once complete it will bring Mariner East’s system capacity to 345,000 b/d. The 16-in. OD Mariner East 2X pipeline has already been installed in this area and will add another 250,000 b/d.

DEP also required that Sunoco dredge the top 6-in. of sediment from 15 acres of Marsh Creek State Park’s Ranger Cove, the site of an August 2020 drilling fluid spill, and replace all fish, turtle, and bird structures impacted. Dredging is expected to begin in April 2022 and be completed by July 2022.

Construction on Mariner East 2 stopped after Sunoco spilled the drilling fluid. Work had begun in February 2017 with an expectation that it would be complete by end-2019.

EPP starts Gillis Lateral natural gas service

Enterprise Products Partners LP (EPP) has started commercial service on its 1-bcfd Gillis Lateral pipeline and the associated expansion of its existing Acadian Haynesville Extension to serve the LNG market on the US Gulf Coast. The 80-mile Gillis Lateral originates near Alexandria, La., on Enterprise’s Acadian Haynesville Extension, and extends to third-party pipeline interconnects near Gillis, La., including multiple pipelines serving LNG liquefaction plants.

To accommodate the additional volumes, EPP increased capacity on its Acadian Haynesville Extension to 2.1 bcfd from 1.8 bcfd by increasing horsepower at its Mansfield compressor station in DeSoto Parish, La.

The legacy Acadian and Haynesville Extension pipelines are part of the Acadian Gas Pipeline system, comprised of about 1,300 miles of natural gas pipelines and leased underground storage. It links natural gas supplies in Louisiana and offshore Gulf of Mexico to distribution companies, electric power plants, and industrial customers in the Baton Rouge-New Orleans-Mississippi River corridor.

EPP’s 378-mile, 1.3 bcfd Haynesville gathering system can treat as much as 810 MMcfd and supplies the Acadian system.