OGJ Newsletter

Feb. 15, 2021


Asia demand contributes to increased US propane exports

US propane exports have been increasing in recent months, mainly to East Asian countries, thanks to cold weather and strong consumption of petrochemical feedstock in that region, according to the latest data in the US Energy Information Administration’s (EIA) Petroleum Supply Monthly.

Between April 2020 and November 2020 about 58% of all US propane exports went to Asia markets. In those months, nearly half of US propane exports were shipped to three countries: Japan, China, and South Korea.

Consumption of propane as petrochemical feedstock in East Asia has been supported by demand for propylene, a base chemical used to manufacture polypropylene. According to China’s customs data, in 2020, Chinese exports of plastics and resins rose 15%, and the year-over-year increase reached an annual peak of 41% in November. In 2020, China’s exports of pharmaceutical preparations and supplies increased 44%.

Other factors have also contributed to the growth in US propane exports to East Asia, according to EIA. Weather-driven demand for propane as a heating fuel increased when the La Niña weather phenomenon resulted in colder winter weather in the region. The US has also accounted for a greater share of propane imports by Asian countries because voluntary reductions in crude oil production in Saudi Arabia have led to fewer exports out of the Middle East, which has traditionally been a major supplier for markets in Asia.

ExxonMobil reports quarterly loss of $20 billion

ExxonMobil Corp. recorded an estimated fourth-quarter 2020 loss of $20.1 billion. The loss included unfavorable identified items of $20.2 billion, primarily non-cash impairments; earnings excluding identified items were $110 million.

Capital and exploration expenditures in the quarter were $4.8 billion, bringing full-year spending to $21.4 billion, $9.8 billion lower than the prior year. Oil-equivalent production in the fourth quarter was 3.7 million b/d, consistent with third-quarter 2020. Excluding entitlement effects, divestments, and government mandates, liquids production increased 5%, while natural gas volumes increased 2%.

Average realizations for crude oil were in line with the third quarter. Natural gas realizations rose by 39% in the quarter, reflecting market supply disruptions and seasonal demand.

For the downstream sector, industry fuels margins improved slightly from the third quarter but remained near historic lows driven by market oversupply and high product inventory levels. Lubricants delivered strong fourth quarter and full-year performance underpinned by improved margins and cost control, despite pandemic-related challenges.

For the chemical segment, fourth quarter earnings of $691 million represent the best quarterly result since 2018, underpinned by strong safety and operational performance, and advantages from integration with refining, the company said. Chemical sales volumes were even with the third quarter, while industry margins strengthened on continued strong packaging demand, automotive and durables market recovery and industry supply disruptions. The company also achieved record full-year polyethylene sales driven by strong performance from recent investments and growing demand for the company’s performance products.

Inpex acquires deepwater Gulf of Mexico interests

Inpex Americas Inc., an Inpex Corp. subsidiary, has acquired 2.35% of 23.30% participating interest previously held by ExxonMobil in Occidental Petroleum-operated deepwater Gulf of Mexico fields Lucius and Hadrian North.

Lucius lies 380 km offshore Louisiana in Keathley Canyon Blocks 874, 875, 918, and 919 in water depth of 2,200 m. Hadrian North, in the vicinity of Lucius in Keathley Canyon Blocks 918 and 919, was unitized with Lucius in 2017 and has since been jointly developed using Lucius’s production facilities.

Crude oil and natural gas from the two fields are processed at an offshore floating production facility with a capacity to process more than 80,000 bo/d and 450 MMscfd of natural gas, shipped to a facility onshore Louisiana via subsea pipelines.

The acquisition increases INPEX’s participating interest to 10.11% from 7.75%.

Exploration & Development Quick Takes

Vintage delays Vali production to optimize development plan

Vintage Energy Ltd., Adelaide, will delay completion of its Vali-1 ST1 gas discovery in southwest Queensland Cooper basin permit ATP2021 to assess upside of the gas resource at the field.

The company will now drill Vali-2 appraisal followed by a well in the nearby Odin prospect that straddles the boundary into permit PRL 221 in South Australia. The wells will be drilled before the flowline infrastructure purchase so that, if successful, they can be combined into the development plan.

Vali-2 will target an interpreted Toolachee formation gas accumulation that could provide additional reserves to those certified for the field in the Patchawarra formation. Both reservoirs are of Permian age.

Vintage also plans to run desktop studies to determine further prospectivity and potential upside in the region.

Benefits of the timing change include the ability to plan an appropriately sized flowline over the long-term and enable the potential for development of a production hub for the area, the company said.

Vali-2 is expected to spud in April-May. Odin-1, in PRL 211, will follow in May-June pending rig availability and other approvals.

The Odin structure lies up-dip of previously drilled Strathmore-1 which intersected interpreted Permian gas pay. The Odin prospect is a Permian four-way dip closure that plunges to the northeast into the Nappamerri Trough.

Odin has been de-risked by the success at Vali-1 ST1 and has potential for gas in the Toolachee formation as well as the Patchawarra formation.

Vintage holds 50% interest and operatorship of ATP 2021 with Metgasco Ltd. (25%) and Bridgeport Cooper Basin Pty Ltd. (25%).

In PRL 211, Vintage holds 42.5% and operatorship with Metgasco (21.25%), Bridgeport (21.25%), and Stuart Petroleum Pty Ltd. (wholly owned by Senex Energy Ltd.) (15%).

Vermilion eyes Q1 activity in Alberta, the Netherlands

Vermilion Energy Inc. has approved a 2021 exploration and development capital budget of $300 million, a 17% reduction from 2020. Some 31% of the 2021 capital budget will be invested during the first quarter, compared to 65% in 2020. The program is expected to deliver annual average production of 83,000-85,000 boe/d.

The majority of the company’s first-half 2021 drilling program will be allocated to its condensate-rich natural gas projects in Alberta and conventional natural gas projects in the Netherlands. Vermilion’s light oil projects in southeast Saskatchewan, Wyoming, and France have been scaled back.

The company has reorganized the business and reporting lines into two core regions, North America and international.   

In North America, the company plans to invest $165 million, a reduction of 37% compared to 2020. The program includes the drilling of 10 (9.6 net) Mannville condensate-rich natural gas wells in Alberta, 25 (22.1 net) light oil wells in southeast Saskatchewan, and four (3.9 net) light oil wells in Wyoming. The company will also bring on production five (5 net) Mannville condensate-rich natural gas wells drilled in fourth-quarter 2020. Additional light oil wells in southeast Saskatchewan and Wyoming have been identified for possible drilling during second-half 2021.

The company expects to invest $135 million across international assets, an increase of 35% compared to 2020. The 2021 drilling program includes two (1.5 net) natural gas wells in the Netherlands, one (1 net) natural gas well in Croatia, and one (1 net) oil well in Hungary. Capital activity in France and Germany will be primarily focused on well workovers to preserve production. Several oil wells have been identified in France for potential drilling during second-half 2021. The previously drilled Burgmoor Z5 well (46% working interest) in Germany is expected to be brought on production in 2021. Capital activity in the remaining international jurisdictions will be focused primarily on maintenance activities, including a 1-week planned turnaround in Ireland and 3 weeks of planned maintenance downtime in Australia.

Drilling & Production Quick Takes

Santos plans exploration offshore western Australia

Santos WA Northwest Pty Ltd. expects a single-well exploration drilling campaign offshore western Australia targeting a gas reservoir in the Legendre formation to begin in this year’s fourth quarter.

Permit area WA-1-P lies within offshore Commonwealth waters at a depth of 63 m. The exploration permit is valid until end-2022.

Drilling activity will be carried out using a jackup mobile offshore drilling unit (MODU) with support vessels and helicopters. A sidetrack or re-spud is not planned but is included as a contingency.

Drilling is expected to take 30 days with contingency planning of up to 75 days to account for unfavorable weather, additional drilling (e.g. a re-spud), or operational challenges.

The well will use water-based drilling fluids with no plans to test surface (i.e. flowing hydrocarbon to surface and flaring). Downhole formation evaluation will include wireline logging, vertical seismic profiling, and coring. After drilling, the well will be plugged for isolation to mitigate risk of potential release of wellbore fluids to the marine environment.

Premier Oil completes Tuna farm out

Premier Oil PLC completed a farm down of its interest in the Tuna production sharing contract (PSC), offshore Indonesia, to ZN Asia Ltd., a subsidiary of Zarubezhneft, following receipt of Indonesian government approval.

Under the agreement, Zarubezhneft will carry Premier for its share of a two well campaign to appraise Tuna discoveries, scheduled to begin in this year’s second quarter.

The companies have secured Indonesian government approval for a 1-year extension of the Tuna PSC exploration period to March 2022.

In April 2014, Premier drilled the Kuda Laut-1 exploration well which discovered 183 ft of net oil-bearing reservoir and 327 ft of net gas-bearing reservoir. Oil and gas samples were also recovered to surface. The well was then sidetracked to drill a prospect at Singa Laut in an adjacent fault block where 177 ft of net gas-bearing reservoir quality sands were penetrated.

Premier remains operator of Tuna (50%) with Zarubezhneft holding the remaining 50%.

Masirah Oil increases activity in Yumna field, Oman

Masirah Oil Ltd. started production from Yumna 2, the second development well drilled in Yumna field, offshore Oman. The well was spudded on Dec. 10, 2020, and production started on Jan. 23, 2021.

The well has been producing at a stabilized rate of 9,000 b/d dry oil. The rate is constrained by the size of the downhole electrical submersible pump. Yumna 2 encountered 10 m of Lower Aruma sandstone with a porosity of 21%, proving that good quality reservoir sand is extensive north of Yumna 1. Permeability is about 2,000 md. Reservoir pressure depletion over the first year of production is about 100 psi, confirming that excellent pressure support is provided by a strong aquifer.

The third production well, Yumna 3, was spudded on Jan. 20, 2021, targeting a crestal location in the field to the east and up-dip from the discovery well GAS-1.

Production facilities on the Yumna Mobile Offshore Production Unit (MOPU) are being upgraded to double liquid processing capacity to accommodate production from the three Yumna wells. The upgrade is scheduled to be completed by the end of the first quarter 2021.

Upon completion of Yumna 3, the Shelf Drilling Tenacious jackup rig will relocate to drill the Zakhera prospect located about 12 km south of Yumna field. This exploration well is targeting a look-alike structure to Yumna field.


ExxonMobil to close Altona oil refinery in Melbourne

ExxonMobil Corp. will close its oil refinery at Altona, an inner western suburb of Melbourne in Victoria.

The decision was made following a review of the facility’s operation which found that Altona can no longer be considered economically viable. The refinery will be converted into a fuels import terminal to ensure ongoing supply for Victoria.

The decision is the latest in a string of refinery closures across Australia in the last few years. Only two remain–Viva Energy’s Geelong refinery in Victoria and Ampol’s Lytton refinery in Brisbane, Queensland.

Altona was the smallest of the country’s refineries, originally built and operated by Mobil from 1949 before being brought under the ExxonMobil umbrella in November 1999.

Altona will remain in operation while transition work is undertaken to ensure continued supply to its customers. The refinery currently employs 350 people and supplies about half of Victoria’s refined fuel demand.

CVR advances alkylation unit revamp at Wynnewood refinery

CVR Energy Inc. has let a contract to KBR Inc. to provide a suite of additional services for the second phase of a previously proposed project to convert process technology of an existing hydrofluoric acid (HF) alkylation unit at subsidiary Wynnewood Refining Co. LLC’s (WRC) 74,500-b/d refinery in Wynnewood, Okla. (OGJ Online, Jan. 24, 2019).

Following CVR Energy’s 2019 contract award to KBR to provide basic engineering and design services for the HF alkylation unit conversion based on the service provider’s proprietary Solid Acid Alkylation Technology (K-SAAT), KBR second-phase scope of work on the project will include delivery of detailed engineering of process equipment, as well as proprietary equipment supply and module fabrication, KBR said on Feb. 4.

Unlike traditional liquid-acid catalysts used in the HF alkylation process, K-SAAT technology uses the ExSact solid-acid catalyst, which is engineered to maximize yield and quality of ultraclean alkylate blendstock for gasoline.

Subject to regulatory and internal approvals, the Wynnewood HF alkylation revamp would reach mechanical completion in late 2024, according to the service provider.

While the Wynnewood unit will be the first US installation of K-SAAT technology, KBR said its first commercial K-SAAT plant has been operating in China since 2018.

Alongside eliminating use of HF acid catalyst in the alkylation unit, CVR Energy told investors in March 2020 that it expects Wynnewood’s HF mitigation project also will increase the refinery’s liquid yield, as well as its production of premium gasoline.

According to its most recent update on the project, CVR Energy estimated overall capital investment in the Wynnewood HF mitigation and yield-enhancement project at about $90 million. The operator also said there is potential to implement a similarly designed project at subsidiary Coffeyville Resources Refining & Marketing LLC’s 132,000-b/d refinery in Coffeyville, Kan.

CVR Energy is currently at work on a $110-million project that will allow WRC to produce about 100 million gal/year of low-carbon renewable diesel and 6 million gal/year of renewable naphtha at the Wynnewood refinery beginning in July 2021.

Limetree Bay restarts long-idled St. Croix refinery

EIG Global Energy Partners-controlled Limetree Bay Ventures LLC has completed its long-planned restart of an idled refinery previously owned and operated by Hovensa LLC at Limetree Bay on St. Croix, USVI.

Now operated by Limetree Bay Refining LLC and equipped with a crude oil processing capacity of more than 200,000 b/d, the renovated refinery has officially resumed operations and started production as well as commercial sales of refined products, Limetree and EIG said in Feb. 1 releases.

Configured to process a mix of feedstocks—including a growing supply of Latin American sour crudes—to fulfill rising demand for transportation fuels in the Caribbean, Central and South America, and the US East Coast, the newly commissioned refinery also will produce low-sulfur fuels that comply with International Maritime Organization (IMO) mandates that took effect in 2020, according to Limetree.

Commissioning of the revamped refinery follows key modernization works at the site that began in 2018, including upgrades to a 62,000-b/d delayed coker unit, extensive desulfurization capacity, and a reformer unit to enable production of clean, low-sulfur marine transportation fuels conforming to IMO 2020 standards (OGJ Online, Sept. 26, 2019).

Hovensa idled the San Croix refinery and transitioned the site into an oil storage terminal in early 2012 to prevent further financial losses resulting from what the then-operator termed the manufacturing site’s “competitive disadvantage” (OGJ Online, Jan. 18, 2012).


Qatar Petroleum takes FID on North Field East

Qatar Petroleum (QP) took final investment decision on its North Field East (NFE) project and signed engineering, procurement, and construction (EPC) contracts for the project’s onshore infrastructure, including LNG trains. NFE will raise Qatar’s LNG production capacity to 110 million tonnes/year (tpy) from 77 million tpy.

The project, being executed by Qatargas also will produce condensate, LPG, ethane, sulfur, and helium. It is expected to start production fourth-quarter 2025 and produce 1.4 million boe/d.

QP awarded the EPC contracts to Chiyoda Corp. and Technip Energies, with their main scope being construction of four 8-million tpy LNG trains. The contracts also cover units for gas treatment, NGL recovery, and helium extraction and refining within Ras Laffan Industrial City. QP last year awarded Baker Hughes Co. a contract for 12 refrigerant compressors for use in NFE’s LNG production (OGJ Online, Sept. 29, 2020).

The project will include a CO2 capture and sequestration (CCS) system that will be integrated with the wider CCS system under development in Ras Laffan. It will also use a jetty boil-off gas recovery system which QP says will reduce greenhouse gas emissions by an additional 1 million tpy of CO2 equivalent. Solar power, water conservation, and NOx-emissions reductions are all also planned as integrated parts of the project’s development.

NFE’s total cost will be $28.75 billion.

The project represents the first phase of LNG expansion in Qatar. The second phase, North Field South (NFS) project, will further increase Qatar’s LNG production to 126 million tpy. With an expected production start date in 2027, NFS involves construction of two additional 8-million tpy trains and associated offshore and onshore infrastructure.

QP is evaluating further LNG capacity expansions beyond 126 million tpy.

Venture Global to develop second Cameron Parish LNG plant

Venture Global CP2 LNG LLC and Venture Global CP Express LLC, both wholly owned subsidiaries of Venture Global LNG Inc., have requested US Federal Energy Regulatory Commission (FERC) approval to initiate National Environmental Policy Act prefiling review for the proposed 20-million tonne/year (tpy) CP2 LNG plant in Cameron Parish, La., and the 48-in. OD, 87.5-mile CP Express natural gas pipeline from Jasper County, Tex., to the LNG plant.

CP2 LNG will include 18 liquefaction trains, each with a nameplate capacity of about 1.1-million tpy, four LNG full-containment storage tanks, two marine loading berths for ocean-going vessels, and an on site 1,440-Mw powerplant. The plant will be built in two 10-million tpy phases, with Phase 1 constructing nine trains, two tanks, a 720-Mw powerplant, the two marine berths, and ancillary infrastructure.

The CP Express pipeline and 84,000 hp of compression at a single station in Vinton, La., also will be built as part of Phase 1; an additional 84,000 hp will be added at the same station in Phase 2. Each phase of compression will use two 42,000-hp units. Phase 1 pipeline capacity will be 2 bcfd, climbing to 4 bcfd in Phase 2.

The project will also include construction 5.5 miles of 24-in. OD lateral pipeline in Calcasieu Parish, connecting CP2 LNG to the existing natural gas pipeline grid in east Texas and southwest Louisiana. CP2’s peak capacity will be 24-million tpy, with 20 million being the minimum output expected to be guaranteed by the project’s contractors.

Phase 1 is expected to begin construction upon receipt of all required regulatory approvals. The construction and operational timelines for Phase 2 will depend on market conditions. Following receipt of FERC authorization and other necessary approvals, CP2 LNG plans to begin construction in second-quarter 2023, commissioning its trains sequentially to make first deliveries of LNG in second-quarter 2025, and achieve full Phase 1 commercial operations by mid-2026.

Venture Global’s first liquefaction project, Calcasieu Pass LNG, is under construction in Cameron Parish (OGJ Online, Nov. 11, 2020) on a site adjacent to the planned CP2 project. Venture Global’s second permitted project, Plaquemines LNG (OGJ Online, Nov. 24, 2020), was authorized by FERC Sept. 30, 2019, and site preparation is expected to begin early 2021.