OGJ Newsletter

April 25, 2022
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


ExxonMobil begins design studies for Australia carbon capture hub

ExxonMobil is undertaking early front-end engineering design studies (pre-FEED) to determine the potential for carbon capture and storage to reduce greenhouse gas emissions from multiple industries in the Gippsland basin.

The South East Australia carbon capture and storage (SEA CCS) hub would initially use existing infrastructure to store CO2 in depleted Bream field off the coast of Gippsland, Victoria. ExxonMobil is in active discussions with local industries which may be interested in accessing the hub to reduce emissions from their operations, the company said in an Apr. 14 release.

The project is designed to capture up to 2 million metric tons/year (tpy) of CO2. If technical and business feasibility is confirmed, the SEA CCS hub could be operational by 2025.

Libya declares force majeure at major ports, fields

Libya’s National Oil Corp. (NOC) suspended operations and declared a state of force majeure at the Zouetina terminal, al-Charara field, and several other sites due to political unrest.

In February, the parliament sitting in Tobruk in eastern Libya appointed Fathi Bachagha the new head of government. Current prime minister Abdelhamid Dbeibah, however, refuses to hand over power before elections are held. The groups blocking the oil sites are demanding revenue distributions and transfer of executive power to Mr. Bachagha.

After the forced closure Sunday of al-Fil field (south), the Zouetina terminal (east), Mellitah (northwest), al-Sarrir (east), and Al Khaleej (east) stopped operations. Production at Abu Al-Tifl (east), al-Intissar (east), and al-Nakhla (east) fields also ceased, as did gas production at plants affiliated to these sites and at the port of Zouetina.

Al-Charara is about 900 km south of Tripoli and normally produces 315,000 b/d out of total national production of more than 1.2 million b/d. It is the main supplier of the Zaouia refinery and is managed by Akakus, a joint venture between NOC, Repsol SA, TotalEnergies SE, OMV Group, and Equinor ASA.

Quebec proceeds with law banning oil, gas production

The Government of Quebec passed Bill 21, effectively signaling an end to petroleum exploration and production and the public financing of those activities, Questerre Energy Corp. said in a release Apr. 13.

The province has agreed to provide financial compensation to the industry as a result.

Bill 21 was approved by the elected representatives of the National Assembly in Quebec. A provisional copy of the legislation is available online. It has received the assent of the Lieutenant Governor of Quebec. The law, in whole or in parts, will come into force at the government’s discretion following the finalization of the associated regulations including the proposed compensation program, the release continued.

“By blocking the development of its natural gas resources with zero-emissions technology for export, Quebec is missing an important opportunity to work with other nations to provide secure, reliable energy for our European allies,” said Michael Binnion, president and chief executive officer of Questerre.

“It also leaves the province highly dependent on imports of natural gas and petroleum that meet more than half their energy needs,” he continued.

The company will assess its legal options as it awaits implementation of the law, Binnion said.

Questerre holds assets in St. Lawrence Lowlands. In January 2020, the company acquired exploration rights to 753,000 net acres in Quebec, associated wells and equipment, geophysical data, and other miscellaneous assets. Post-closing, Questerre held rights to about one million net acres covering an established gas resource. A best estimate of unrisked gross contingent and prospective resources by an independent party as of Dec. 31, 2017, for the majority of the acreage was 3.9 tcf and 21.3 tcf, respectively.

In 2021, as a result of the then-proposed legislation, the company impaired the full carrying amount of its exploration and evaluation assets in Quebec of $104 million.

Vermilion to acquire Montney assets from Leucrotta

Vermilion Energy Inc., Calgary, has agreed to acquire Montney-focused Leucrotta Exploration Inc. for a net cash purchase price of $477 million.

Leucrotta holds oil and natural gas assets in the Mica area of Northeast British Columbia and Northwest Alberta. The property comprises 81,000 gross (77,000 net) contiguous acres of Montney mineral rights in the Peace River Arch straddling the Alberta and British Columbia borders.

In 2023, the assets to be acquired are expected to produce about 13,000 boe/d, with anticipated capacity to grow to a sustainable plateau production base of 28,000 boe/d over the next few years, Vermillion said.

Assuming a second-half May 2022 closing date, Vermillion plans to invest $75 million for the remainder of 2022 in the assets which will include drilling a 6-well pad in Alberta as well as infrastructure development.

As part of the deal, a portion of the Leucrotta land base and some $43.5 million in cash will be transferred to a new company (ExploreCo) which will be managed by the existing Leucrotta team. Vermilion will acquire a 12.5% equity stake in ExploreCo for $14 million and obtain board representation and other investor rights.

Vermilion is increasing its 2022 exploration and development budget to $500 million and increasing its annual production guidance to 86,000-88,000 boe/d to account for the deal.

With the execution of the planned Mica drilling program and the anticipated close of the Corrib acquisition in second-half 2022, the company expects to exit 2022 with corporate production of 95,000-100,000 boe/d. In 2021, Vermilion agreed to acquire Equinor Energy Ireland Ltd., which owns a 36.5% interest in the Vermillion-operated Corrib gas project in Ireland, for $434 million.

The revised guidance does not include contribution from the Corrib acquisition.

The Leucrotta deal remains subject to certain closing conditions.

Brazil’s ANP awards 59 blocks to 13 companies in auction

Brazil’s National Agency of Petroleum, Natural Gas and Biofuels (ANP) held a permanent offer bid round in Rio de Janeiro where 59 exploratory blocks were acquired in six basins by a total of 13 companies.

The auction totaled 422.4 million reais ($90.10 million) in signature bonus, with investments set to take place in six states: Rio Grande do Norte, Alagoas, Bahia, Espírito Santo, Santa Catarina, and Paraná, the agency said in an Apr. 13 release. 

Shell Brasil (70%), in partnership with Ecopetrol Óleo e Gás (30%) purchased blocks SM-1599, SM-1601, SM-1713, SM-1817, SM-1908, and SM-1910, all in the Santos basin. Shell Brasil will operate the blocks and pay a total of R$98.158 million in signature bonuses.

With the addition of the new blocks, Shell now owns over 30 oil and gas contracts in Brazil.

Petro-Victory, Calgary, was awarded 19 new oil and gas blocks in Potiguar basin, Brazil, increasing its portfolio in the country to 38 blocks (37 in Potiguar basin). The new blocks cover 128,080 acres (518 sq km) and lie adjacent to Petro-Victory’s operating infrastructure at Andorinha, Alto Alegre, and Trapia oil fields.

Other operators with winning bids include TotalEnergies EP, Origin, Petroborn, 3R Petroleum, among others.

 Exploration & Development Quick Takes

Equinor receives approval for Bay du Nord development

Equinor Canada Ltd. received approval from the Government of Canada for development of the deepwater Bay du Nord oil discovery in the Jurassic reservoirs of the Flemish Pass basin, about 500 km east of St. John’s, Newfoundland and Labrador.

Bay du Nord, in 1,170 m of water, holds reserves of 300 million bbl of 34° gravity oil, including volumes from Equinor’s nearby Bay de Verde and Baccalieu discoveries, both made in 2016.

An environmental assessment report determined that the project is not likely to cause significant adverse environmental effects when mitigation measures are considered. Conditions include requirements to reduce greenhouse gas emissions (GHGs) and measures to protect fish and fish habitat, migratory birds, species at risk, air quality, human health, and indigenous peoples’ use of resources.

Bay du Nord is the first offshore oil and gas production project to complete a federal environmental assessment process under the Canadian Environmental Assessment Act, 2012 (CEAA 2012). It is the province’s fifth development.

Equinor estimates the project will emit as little as 8 kg CO2/bbl of production, compared to the average oil sands emissions of 80 kg CO2/bbl and the overall Canadian average of 40 kg CO2/bbl. Net-zero GHG emissions must be achieved by 2050.

Equinor is operator of Bay du Nord and holds a 65% working interest. Cenovus Energy gained 35% interest with its 2021 acquisition of Husky Energy.

TMK Energy intersects gassy coal in Mongolia

TMK Energy Ltd. has intersected 44 m of gassy coal in the upper coal seam in the first well of its inaugural drilling program in the Gurvantes XXXV coal-seam gas project in South Gobi basin, Mongolia. The coal lies at depths of 406-461 m.

Preliminary results from 36 desorption samples indicate the coal seam has high gas content (7.5-12.5 cu m/tonne) and high gas saturation. A visual assessment of the coal core suggests the coal has a well-developed cleat system which is a positive indicator for permeability.

The well was drilled to 480 m and paused to allow for downhole geophysical surveys to confirm net coal thickness and identify intervals for drill-stem testing. TMK plans a further three core holes spaced about 3.5 km apart for drilling and testing during the next 3-4 months.

The company hopes that resulting data will enable it to convert a portion of the independently certified 5.96 tcf gross prospective resource into a maiden contingent resource for the Nariin Sukhait area during second-half 2022.

Farm-in participant Talon Energy Ltd. is funding the drilling under a $4.65-million, two-stage agreement executed in February 2021. Initial funding of $1.5 million has been allocated to the current four-well drilling and testing program. The second stage of funding ($3.15 million) is budgeted towards the pilot well program planned for later this year should Talon elect to proceed.

Santos well intersects reservoirs, but no commercial discovery

Santos Ltd. and Carnarvon Energy Ltd. will gather information from the Apus-1 wildcat to evaluate further exploration in the Bedout sub-basin offshore Western Australia as commercial hydrocarbons were not discovered (OGJ Online, Apr. 8, 2022).

Interpretation from the logging while drilling and mud logging equipment confirm the intersection of quality reservoirs in Caley and Milne sands as expected, but without a commercial hydrocarbon pool, Carnarvon said in an Apr. 19 release.

The well lies 27 km southwest of the joint venture’s March Pavo-1 oil discovery and had been mapped straddling the permit boundary between WA-437-P, which contains Dorado field, and WA-438-P, which contains Pavo. The well lies in WA-437-P.

Hydrocarbon charge and seal were recognized as risks for the Apus-1 well pre-drill. Early interpretation of drilling results indicates there is evidence of hydrocarbons migrating to the Apus location; however, they may not have migrated in sufficient quantity for a commercial hydrocarbon pool to form, or sufficient hydrocarbons were not able to be retained within the closure that was drilled, Carnarvon said.

“Collectively, the Pavo-1 and Apus-1 results open up the potential of the Bedout Sub-basin by proving the existence of hydrocarbons and high-quality reservoirs a considerable distance east and southeast from Dorado and Roc fields,” said Carnarvon Managing Director and Chief Executive Officer Adrian Cook.

Santos holds 80% interest in WA-437-P. Carnarvon holds 20%. In WA-438-P, Santos holds 70% interest and Carnarvon holds 30%. Santos is operator for both permits.

Petrobras discovers oil in southern Campos basin

Petroleo Brasileiro SA (Petrobras) discovered a new oil accumulation in the Alto de Cabo Frio Central block in the presalt, southern portion of Campos basin, 230 km from Rio de Janeiro in 1,833 m of water. The consortium will continue drilling the well to the originally planned final depth to assess dimensions of the new accumulation and to characterize quality of the fluids and reservoirs found.

The oil-bearing interval in wildcat well 1-BRSA-1383A-RJS was verified by logging and oil samples, which will later be characterized by laboratory analyses. 

The Alto de Cabo Frio Central block was acquired in October 2017, in the 3rd bidding round of the National Agency for Petroleum, Natural Gas and Biofuels (ANP), under the Production Sharing regime, with Pré-Sal Petróleo SA (PPSA) as manager.

Petrobras is operator of the block (50%) with partner bp Energy do Brasil Ltda. (50%).

 Drilling & Production Quick Takes

VAALCO advances Gabon drilling with Avouma 3H-ST

VAALCO Energy Inc. has drilled the Avouma 3H-ST development well from the Avouma platform in Etame field, offshore Gabon.

The development well was drilled with a 268-m lateral in high-quality Gamba sands with 28% porosity and 1-darcy permeability at the top of the structure. Drilling confirmed the extension of Avouma reservoir and is forecast to increase overall recovery from the field, potentially allowing for additional wells at Avouma. Initial production is expected in the next few weeks.

Following completion, the drilling program will continue with spudding of the ETBSM-1HB ST2 development well from the Avouma platform.

Etame Marin block is in Congo basin about 32 km off the coast of Gabon and has produced more than 125 million bbl of crude oil to date. The license area is spread over five fields covering a total area of about 187 sq km (OGJ Online, Feb. 7, 2022).

VAALCO is operator of Etame Marin field (63.6%) with partners Addax Petroleum Co. (33.9%) and PetroEnergy Resources Corp. (2.5%).

Neptune plans appraisal following hydrocarbon encounter at Hamlet

Neptune Energy Norge AS has been granted permission by the Norwegian Petroleum Directorate to drill appraisal well 35/9-16 A in production license 153 in the North Sea.

The well—to be drilled in April by Odfjell Drilling’s Deepsea Yantai semisubmersible—follows a hydrocarbon encounter at the Hamlet exploration well, 58 km west of Florø in March (OGJ Online, Mar. 22, 2022).

Neptune Energy is operator with 30%. Partners are Petoro AS (30%), Wintershall Dea Norge AS (28%), and OKEA ASA (12%).

Aker BP starts production at Hod B

Aker BP ASA started production from Hod B in the southern North Sea.

Hod field lies in Block 2/11 in the Norwegian sector of the North Sea, about 12 km south of Valhall and 6 km south of the Valhall Flank South platform. The platform will be remotely operated from Valhall.

Aker BP expects Hod to produce 40 million bbl of oil.

In the period leading up to production start-up, Subsea 7 SA installed and connected gas lift pipelines, production flowlines, and umbilicals. The Maersk Invincible jackup rig drilled six production wells, and modification work has been carried out at Valhall field center.

Aker BP is operator with 90% interest. Pandion Energy holds the remaining 10%.

Petronas starts production from Bukit Tua Phase-2B

PC Ketapang II Ltd., a Petroleum National Bhd. (Petronas) subsidiary, produced first hydrocarbons from Bukit Tua Phase-2B’s BTJTB-T2 well within Ketapang block, about 100 km offshore East Java, Indonesia.

The well was spudded Sept. 30, 2021, and drilled with a target depth of 1,890 m. This is the fourth development project after Bukit Tua Phase 1, Phase 2A, and Phase 3. The project aims to produce 12,500 boe/d and 30 MMscfd through five development wells.

Petronas is operator of Ketapang block (80%) through two subsidiaries, PC Ketapang II Ltd. and Petronas Carigali (Ketapang) Ltd. The remaining 20% is held by PT Saka Ketapang Perdana.

Eni ties in production in Egypt’s Western Desert

Eni SPA has tied-in to production new oil discoveries in the Meleiha concession of the Western Desert in Egypt. The discoveries add 8,500 boe/d to the current concession production, the company said in a release Apr. 13. 

The Nada E Deep 1X well encountered 60 m net hydrocarbon pay in the Cretaceous-Jurassic Alam El Bueib and Khatatba formations. The Meleiha SE Deep 1X well found 30 m net hydrocarbon pay in the Cretaceous-Jurassic sands of the Matruh and Khatatba formations, and the Emry Deep 21 well encountered 35 m net hydrocarbon pay in the Cretaceous sandstones of Alam El Bueib.

These results, added to 2021 discoveries, total eight exploration wells with 75% success rate, and confirm the area’s potential, Eni said. The company recently acquired two exploration blocks in the Western Desert and plans a new high-resolution 3D seismic survey in the Meleiha concession this year. The survey will investigate the area’s gas potential.

The Meleiha concession is operated by Agiba, a 50-50 joint venture between Egyptian General Petroleum Corp. and Eni through its subsidiary, IEOC, which holds a 76% interest in the concession. PJSC Lukoil holds the remaining 24%.

Empyrean Energy drills Jade well, offshore China

Empyrean Energy PLC spudded the LH 17-2-1 well on the Jade prospect in Block 29/11 within Pearl River Mouth basin, offshore China.

The drilling objective for the well is to test for hydrocarbons down to 2,860 m TD. A 36-in. surface hole was drilled to 588 m MD and a 30-in. surface conductor is being installed.

Following the setting of the surface conductor, the 17 1/2-in. hole will be drilled to 1,050-m MD and a 13 5/8-in. casing will be set and cemented in place. The rig will drill a 12 1/4-in. hole to about 2,140 m MD before setting 9 5/8-in. casing. After setting the casing, the rig will drill ahead in the 8 1/2-in. hole section to expected TD.

Logging while drilling is being conducted. Should hydrocarbons be encountered in the main target zone, additional combo logs will confirm oil pay zones. In the event of pay zone confirmation, Empyrean Energy will perform flow testing operations.

Initial geological chance of success (GCoS) was 32%, but subsequent gas cloud and post-stack seismic inversion study increased GCoS to 41%. The seismic inversion study showed that Jade has the potential for excellent carbonate buildup reservoir quality with excellent porosity and permeability. Any oil discovered is expected to be in the 38-41° API range, like nearby discoveries.

The Jade prospect is the first of the three identified prospects within Block 29/11, which also contains the Topaz and Pearl prospects. Jade has 225 million bbl mean in place potential and 395 million bbl P10 potential in place. The combined mean in place potential of all three prospects is 884 million bbl with 1,588 million bbl P10 potential in place.

Empyrean is operator of the block and holds 100% working interest during the exploration phase. In the event of a commercial discovery, partner CNOOC may assume a 51% participating interest in the development and production phase.


Viva advances plans to upgrade Geelong refinery

Viva Energy Group Ltd. approved funding to upgrade the Geelong oil refinery to produce ultra-low sulphur gasoline.

The improvement in quality of petrol produced at the refinery, which lies 50 km west of Melbourne in Victoria, will help reduce vehicle emissions and improve the refinery’s crude processing flexibility, Viva said.

Project cost is estimated at $300 million (Aus.) with Viva receiving $125 million under the Australian Federal Government’s refinery upgrades program.

The project is expected to be completed over the next 3 years, with some $50-70 million likely to be spent this year.

Viva recently committed to continue refining in Australia through mid-2028 and to construct an additional 90 ML of diesel storage to improve Victoria’s fuel supply security.

Separately, Viva agreed to acquire LyondellBasell Australia (LBA), a Geelong-based national polymer manufacturer and distributor which has its production infrastructure inside the Geelong refinery footprint.

LBA is Australia’s only polypropylene manufacturer with customers across Australia, New Zealand, Asia, India, the Middle East, and North America.

SOCAR modernizing Heydar Aliyev refinery

State Oil Co. of Azerbaijan Republic (SOCAR) is modernizing its 120,000-b/d Heydar Aliyev refinery. Work began Apr. 4, 2022, to increase refining capacity, provide the country with Euro-5 fuel, reduce the plant’s environmental impact, ensure Azerikimya IB SOCAR’s feedstock supply, and raise export capacity of oil products.

The work is the first scheduled maintenance on the refinery in more than a year.  

SOCAR says it started building fuel reserves in February 2022 and has taken necessary measures to ensure uninterrupted supply of motor fuels to Azerbaijan’s domestic market while the work is under way. This includes portions of the former Azerneftyag oil refinery, which is now part of the Heydar Aliyev, continuing to operate and produce kerosene, diesel, and gasoline. 

TotalEnergies, ENEOS launch study for SAF production at Negishi refinery

TotalEnergies SE and ENEOS Corp. Ltd. are conducting a joint feasibility study to assess potential future production of sustainable aviation fuel (SAF) at ENEOS’s 270,000-b/d Negishi refinery in Yokohama City, Kanagawa Prefecture, Japan.

Already under way, the joint feasibility study is evaluating feedstock procurement and production options for a possible unit at Negishi that, if approved, would be able to produce 300,000 tonnes/year (tpy) of SAF from sustainable waste procured from the circular economy, including used cooking oil and animal fat, TotalEnergies and ENEOS said in separate mid-April releases.

Currently, both companies are in the process of collecting the sustainable feedstock options from Yoshikawa Oil & Fat Co. Ltd. in collaboration with HMLP Co. Ltd. to determine the possibility of building a stable system for procuring used cooking oil from all over Japan, ENEOS said.

The companies’ planned collaboration at the Negishi refinery—which, near to both the Narita and Haneda airports, is in Japan’s largest aviation fuel demand area—would include establishment of a new joint venture (JV) for the proposed SAF production, according to the operators.

While TotalEnergies and ENEOS did not reveal a detailed timeline for the proposed venture, the companies did express a mutual hope to develop a reliable SAF supply chain in Japan by 2025.

The operators said the potential partnership comes as part of both companies’ commitments to responding to the challenges of global climate change as well as their individual goals to decarbonizing operations in line with the energy transition.

Specifically, the proposed project would enable ENEOS to help further its corporate Long-Term Vision to 2040 for development of a decarbonized, recycling-oriented society, as well as further the goal of Japan’s Ministry of Land, Infrastructure, Transport and Tourism to achieve 10% SAF use throughout the country by 2030, the company said.

TotalEnergies, which continues to invest in renewables-based fuel production across its operating platforms, said the Negishi project would complement its broader transformation into a multi-energy operator equipped to achieve net-zero emissions by 2050.

The potential SAF project at the refinery would follow the planned October 2022 decommissioning of the Negishi refinery’s 120,000-b/d Topping Unit No. 1, as well as related secondary units for vacuum distillation, catalytic cracking, and lube oil manufacturing, which will reduce the refinery’s crude processing capacity to 150,000 b/d, ENEOS said in a Jan. 14, 2021, release.


Commonwealth LNG draft EIS notes adverse environmental impacts

The US Federal Energy Regulatory Commission (FERC) has prepared a draft environmental impact statement (EIS) for Commonwealth LNG LLC’s 8.4-million tonne/year LNG plant, proposed by for development in Cameron Parish, La. FERC staff concluded that approval of the proposed project, with the mitigation measures recommended in the EIS, would result in some adverse environmental impacts. 

Most of these impacts would be reduced to less than significant levels, but FERC staff concluded there would be significant impacts on visual resources and environmental justice communities. Environmental justice communities are those most impacted by environmental harms or risks.

In addition to the plant itself, the project would include two flare systems; six 50,000-cu m LNG storage tanks; one LNG carrier berth, a barge dock, and vessel maneuvering area; 3 miles of 42-in. OD pipeline including two interconnections with existing natural gas pipelines; and one metering station. The pipeline would ship 1.44 bcfd of gas to the plant. 

Commonwealth LNG intends to close on development funding in second-quarter 2022 and expects full FERC approval by the end of the year. It would start construction in third-quarter 2023 to begin commercial operations by third-quarter 2026.

As part of its analysis, FERC staff developed specific mitigation measures that the Commission described as practical, appropriate, and reasonable for the construction and operation of the plant and included them in the draft EIS as recommendations, recommending that these mitigation measures be attached as conditions to any authorization eventually issued by FERC.

This EIS did not characterize the project’s greenhouse gas emissions as significant or insignificant, FERC describing the draft EIS as a generic proceeding to determine whether and how it will conduct significance determinations going forward.

The draft EIS comment period closes May 23, 2022. The Commission will take into consideration staff’s recommendations when it makes a decision on Commonwealth LNG.

Sempra granted, NextDecade requests, FERC extensions for LNG projects

Sempra Infrastructure has received US Federal Energy Regulatory Commission (FERC) approval of its request for an extension to build Port Arthur Pipeline LLC’s 2-bcfd Texas Connector and Louisiana Connector pipelines. The company now has until Mar. 31, 2023, to submit its implementation plan for the projects, both of which would supply natural gas to its planned 13.5-million tonne/year (tpy) Port Arthur LNG plant in Port Arthur, Tex.

Sempra last year delayed final investment decision (FID) on Port Arthur LNG to 2022, saying it needed production from the plant to be fully contracted before making that decision (OGJ Online, May 7, 2021). Polish Oil & Gas Co. SA had a 2-million tpy agreement for Port Arthur offtake, but it and Sempra modified this in 2021 to 2 million tpy from Sempra’s North American liquefaction plants.

In addition to Port Arthur LNG, Sempra operates 12-million tpy Cameron LNG in Louisiana and is developing the 3.25-million tpy Energia Costa Azul plant on Mexico’s Pacific coast.

NextDecade Corp., meanwhile, has requested a FERC extension to Nov. 22, 2028, to put its planned 27-million tpy Rio Grande LNG plant in Brownsville, Tex., into service. NextDecade ascribed the request to “unforeseeable developments in the global LNG market as a result of the COVID-19 pandemic,” as had Sempra in its Port Arthur request.

Recently, NextDecade executed a 20-year sales agreement for 1.5 million tpy of Rio Grande production with ENN LNG (Singapore) Pte. Ltd. The producer had anticipated Train 1 startup as early as 2026.