OGJ Newsletter

March 7, 2022
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Seplat Energy to acquire ExxonMobil’s producing Nigeria shallow-water affiliate

Seplat Energy, a Nigerian independent oil and gas company, through its wholly owned subsidiary Seplat Energy Offshore Ltd., has agreed to acquire the equity interest of ExxonMobil in Mobil Producing Nigeria Unlimited for $1.283 billion plus up to $300 million contingent consideration.

When finalized, the sale will include the Mobil Development Nigeria and Mobil Exploration Nigeria equity ownership of Mobil Producing Nigeria Unlimited, which holds a 40% stake in four oil mining licenses (OMLs 67, 68, 70, 104) including more than 90 shallow-water and onshore platforms and 300 producing wells.

The deal includes the Qua Iboe terminal, one of Nigeria’s largest export facilities and 51% interest in the Bonny River Terminal and Natural Gas Liquids (NGL) Recovery plants at EAP and Oso.

With the transaction, Seplat adds working interest production of 95,000 boe/d, 445 MMboe 2P reserves (92% liquids), and upside from potential LNG development in global markets with total working interest gas resources of 2.9 tcf (7.3 tcf JV), Seplat said in a February investor presentation.

Operating costs/bbl in 2020 were about $18/boe, according to Seplat.

The sale will not result in any loss of employment and is expected to close later this year subject to regulatory and other approvals, ExxonMobil said in a Feb. 25 statement.

ExxonMobil will maintain a deepwater presence in Nigeria, including interests in the Erha, Usan, and Bonga developments via Esso Exploration and Production Nigeria Ltd. and Esso Exploration and Production Nigeria (Deepwater) Ltd.

Chevron to accelerate renewables growth with acquisition

Chevron Corp. has agreed to acquire Renewable Energy Group Inc. (REG) in an all-cash transaction valued at $3.15 billion.

The acquisition combines REG’s growing renewable fuels production and feedstock capabilities with Chevron’s manufacturing, distribution, and commercial marketing position.

The transaction is expected to accelerate progress toward Chevron’s goal to grow renewable fuels production capacity to 100,000 b/d by 2030 and brings additional feedstock supplies and pre-treatment infrastructure, Chevron said in a release Feb. 28. In September 2021, the oil and gas giant said it plans to triple its total capital investment to $10 billion through 2028 to grow its lower carbon energy businesses including growth targets for renewable fuels, hydrogen, and carbon capture through 2030 (OGJ Online, Sept. 14, 2021).

After closing—expected in second-half 2022 subject to REG shareholder approval, regulatory approvals, and customary closing conditions—Chevron’s renewable fuels business, Renewable Fuels - REG, will be headquartered in Ames, Iowa. Cynthia (CJ) Warner, REG’s current president and chief executive officer, is expected to join Chevron’s board of directors.

The transaction is expected to be accretive to Chevron earnings in the first year after closing and accretive to free cash flow after start-up of REG’s 250-million gal/year capacity expansion and improvement project at its existing renewable diesel refinery in Geismar, Ascension Parish, La. (OGJ Online, Nov. 3, 2021).

NPD increases Norway-shelf resource estimate

Norwegian Petroleum Directorate, Stavanger, estimated recoverable resources on the Norwegian continental shelf at 15.86 billion standard cu m of oil equivalent, comprised of 8.31 billion cu m of oil and 6.61 billion cu m oil equivalents of gas.

Proven resources at yearend 2021 increased by 142 million cu m of oil equivalent compared with the previous year’s accounts. About two-thirds, or 65%, of the increase is for gas.

The reserve growth, in other words, how much of the resources have a positive development decision, was also good—particularly for gas. The increase was 165 million cu m oil equivalents compared with the 2020 accounts.

The most important reason for the increase is that more development plans (PDOs) were submitted in 2021. Reserves in fields also increased, in part due to expectations for extended operating periods on several fields.

The total estimate for undiscovered oil and gas resources is practically unchanged, but new information has resulted in changes as regards the distribution of the undiscovered resources. Liquid resources in the Norwegian Sea have increased, while both gas and liquid resources in the Barents Sea South are reduced.

The fields with the greatest remaining oil reserves as of Dec. 31, 2021 are Johan Sverdrup (346 million cu m), Johan Castberg (90 million cu m), and Snorre (74 million cu m). The remaining gas reserves are greatest in Troll (685 bcm), Snøhvit (148 bcm), and Ormen Lange (105 bcm).

Twenty discoveries were made in 2021, 18 in exploration wells and two in development wells with exploration targets. Thirteen of the discoveries were made in the North Sea, four in the Norwegian Sea, and three in the Barents Sea.

TotalEnergies halts additional investment in Russian projects

TotalEnergies said it condemns Russia’s military aggression against Ukraine and will no longer provide capital for new projects in Russia. The energy major said it “supports the scope and strength of the sanctions put in place by Europe,” and will implement them.

In Russia, the company holds a 19.4% interest in Novatek, the country’s largest independent natural gas producer. Alongside Novatek, the company holds interests in three LNG projects. 

It holds a 20% interest in the Yamal LNG joint venture, which develops the resources of South Tambey gas and condensate field and liquefies gas in the Yamal LNG plant. In 2020, Yamal LNG produced 18.8 million metric tons of LNG, exceeding the three trains’ design capacity by 14%, or 2.3 million metric tons. Some 255 LNG cargos (18.6 million metric tons of LNG) and 24 stable gas condensate cargos (1 million metric tons) were shipped to international markets.

A 49% interest is held in the ZAO Terneftegas joint venture, which develops Termokarstovoye onshore gas and condensate field located in the Yamalo-Nenets region.

The company also holds a 21.64% interest in Arctic LNG 2, an LNG project on the Gyda peninsula, opposite the Yamal peninsula, which aims to tap oil and gas resources in onshore Utrenneye gas and condensate field. It will consist of three liquefaction trains capable of producing 19.8 million tonnes/year of LNG and 1.6 million tonnes/year of initial condensate. Final investment decision on the project was made in September 2019 (OGJ Online, Sept. 5, 2019). Construction is ongoing, and the first train is scheduled to start up in 2023, with the second train in 2024 and the third train in 2025.

TotalEnergies also holds 20% interest in the onshore Kharyaga oil field, which is in production.

The move is short of intentions relayed by bp, Equinor, and Shell, which have announced intent to withdraw from Russian projects (OGJ Online, Feb. 28, 2022).

Exploration & Development Quick Takes

TotalEnergies makes discovery offshore Namibia

TotalEnergies EP Namibia BV discovered light oil with associated gas on the Venus prospect in Block 2913B about 250 km offshore southern Namibia in 2,600-3,300 m of water.

The Venus 1-X well encountered about 84 m net oil pay in a good quality Lower Cretaceous reservoir. A comprehensive coring and logging program has been completed and will enable preparation of appraisal operations to assess commerciality.

Block 2913B covers about 8,215 sq km in Orange basin, immediately adjacent to the South Africa maritime boundary. The acreage lies along the western toe of the Orange River delta, where laterally extensive, large Cretaceous basin-floor fan sands are contained.

TotalEnergies is operator of the block with 40% interest. Partners are QatarEnergy (30%), Impact Oil and Gas Ltd. (20%), and NAMCOR (10%).

Drilling & Production Quick Takes

Eni starts up Ndungu Early Production project offshore Angola

Eni SPA started production from the Ndungu Early Production (EP) development project in Block 15/06, about 120 km from Angola in 1,050 m of water, via the Ngoma Floating Production Storage and Offloading (FPSO) vessel. Additional exploration and delineation will be performed in this year’s first half to assess the full potential of the overall Ndungu asset.

The project, with an expected production rate of 20,000 b/d, will sustain the plateau of the Ngoma, a 100,000-bo/d zero-discharge and zero-process flaring FPSO.

Ndungu EP is the third start-up by Eni Angola in Block 15/06 in the last 7 months, after Cuica Early Production and Cabaca North Development Project (OGJ Online, Sept. 27, 2021).

Eni Angola and partners, in cooperation with Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG), will fast-track subsea tiebacks to maximize existing infrastructure in the area.

Eni Angola operates the block with 36.84% interest. Partners are Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Ltd. (26.32%).

Buru Energy’s Rafael-1 tests gas to surface

Buru Energy Ltd., Perth, flowed gas to surface from the Rafael-1 wildcat in a 70 m open-hole section below the 7-in. casing shoe at 3,868 m depth. The well lies in exploration permit EP 428, onshore Canning basin in Western Australia.

An initial stabilized portion of the clean-up period flowed gas at 4-5 MMcfd through a 32/64-in. fixed choke with a wellhead flowing pressure of 970 psi.

The indicative condensate to gas ration was estimated to be 20-30 bbl of condensate per MMcf of gas. Field measurements need to be verified by the continued sampling program and laboratory analysi, Buru said.

Gas quality was good with only 2% CO2 content observed. Bottom-hole pressures were over 6,000 psi.

Rafael-1 was drilled in late 2021 with several zones of interpreted gas saturations encountered in conventional dolomite reservoirs. The lowermost zone in the main Ungani Dolomite equivalent section was interpreted to have a total 165 m gas column. Testing is being done on the lower 70 m.

Testing will resume with longer flow periods once the current Cyclone Anika alert for the region has abated.

Buru Executive Chairman Eric Streitberg said the flow is the first sustained gas flow from conventional reservoirs in the onshore Canning basin.

Plans are in place to test other zones in the well, including the upper section of the Ungani Dolomite, where gas influx occurred during drilling, and the Upper Laurel Carbonate section, both of which are behind casing.

Buru is operator with 50% interest. Origin Energy Ltd., Sydney, holds the other 50%.

Elixir begins 2022 drilling program in Mongolia

Elixir Energy Ltd., Adelaide, has spudded the first well of a 24-well coal seam gas (CSG) exploration and appraisal program planned for 2022 across its 100%-owned Nomgon IX Coal CBM Production Sharing Contract in the Gobi basin of southern Mongolia.

The first, the Tim-1S exploration well, lies south of the Tavan Tolgoi coal mining area in where the company has mapped a potential coal-bearing depocentre, Elixir said.

The well is targeting Jurassic and Permian-age coals and has a planned total depth of 700 m.

Elixir intends to engage three drilling companies to carry out the 2022 program.

A key focus is a two-well extended pilot production program scheduled to begin mid-year that will involve up to 6 months of fluid pumping activity. Preparations are on track and several long-lead items are on their way to Mongolia, the company said.

A successful pilot program will affirm commercial gas flows and facilitate Elixir’s proposed gas-fired generation project in the Nomgon region.

The 2022 program will be the largest undertaken by Elixir in Mongolia.


bp lets contract for renewable fuels project at former Australian refinery

bp plc has let a contract to Honeywell UOP LLC to license technology for conversion of existing but idled hydroprocessing equipment as part of the preliminary front-end engineering design (pre-FEED) phase for a proposed renewable diesel and sustainable aviation fuel (SAF) project at the operator’s former refinery in Kwinana, south of Perth, on Australia’s western coast.

As part of the contract, UOP will deliver licensing of its UOP-Eni SPA codeveloped proprietary Ecofining process technology to revamp conventional and underutilized hydroprocessing equipment at the site for production of 10,000 b/d diesel and SAF from renewable feedstocks, the service provider said on Feb. 28.

Still under development and aligned with bp’s broader goal of becoming a net-zero company by 2050 or sooner, the planned renewable diesel and SAF project would be integrated with the operator’s existing terminal operations at Kwinana, bp and UOP said.

“[T]his renewable diesel and SAF project will leverage existing infrastructure, including former refining assets, storage, and distribution facilities, and a team with extensive operational capabilities and experience,” said Justin Nash, senior manager for bp’s Corporate & Cities Integrated Solutions division.

Alongside contributing to bp’s achievement of a net-zero future, the proposed project also comes as part of the company’s ambition to develop an integrated clean energy hub at Kwinana, according to Nash.

Further details regarding the previously announced Kwinana renewable diesel and SAF project, including an estimated timeframe for its implementation, have yet to be revealed.

bp announced in late 2020 its decision to shutter refining operations at Kwinana and convert the site into a fuel import terminal amid poor refining margins resulting from an oversupply of finished products in the region.

Borouge commissions new unit at Ruwais petrochemical complex

Abu Dhabi Polymers Co. Ltd. (Borouge), a joint venture of Abu Dhabi National Oil Co. (ADNOC) and OMV AG’s majority held Borealis AG, has commissioned the partnership’s fifth polypropylene plant (PP5) at Borouge’s integrated polyolefins complex in Ruwais, about 250 km west of Abu Dhabi City, UAE (OGJ Online, Mar. 21, 2019; July 13, 2018).

Officially in operation as of Feb. 24 and located within the Borouge 3 complex, the new PP5 unit is designed to produce 480,000 tonnes/year (tpy) to increase Borouge’s total PP production capacity by more than 25% to 2.24 million tpy to meet growing global demand for raw PP used to manufacture more sustainable and readily recyclable advanced packaging, infrastructure, and other industrial materials by the operator’s key customers across the Middle East, the Asia Pacific, and Africa, Borouge, Borealis, and OMV said in separate releases.

Alongside increasing Borouge’s overall PP production capacity, the PP5 unit also will boost the operator’s total polymer capacity of polyolefins by 11% to 5 million tpy from 4.5 million tpy, the companies said.

Commercial operation of PP5—which began commissioning activities in late 2021—follows the partnership’s November 2021 final investment decision (FID) to move forward with its previously proposed fourth expansion of Borouge’s integrated polyolefins complex (Borouge 4), which will involve construction of a new 1.5-million tpy ethane cracker, two polyethylene plants based on Borealis’ proprietary Borstar technology, and a cross-linked 1.4-million tpy polyethylene plant to further meet rising demand for polyolefins by manufacturers in the Middle East, Africa, and the Asia Pacific.

Scheduled to become operational by yearend 2025, the Borouge 4 complex will boost the operator’s Ruwais sitewide production capacity of polyolefins—including polyethylene and PP—to 6.4 million tpy to make it the largest single-site polyolefins complex in the world, the operator said.

LUKOIL begins supply of green electricity to Nizhny Novgorod refinery

PJSC LUKOIL has started supplying electricity generated from the second-stage solar power plant (SPP) located at subsidiary OOO LUKOIL-Volgogradneftepererabotka’s 14.8-million tpy Volgograd refinery in southern Russia to fellow subsidiary LLC Lukoil-Nizhegorodnefteorgsintez’s (NNOS) 17-million tpy Kstovo refinery in central Russia’s Nizhny Novgorod region.

Following the mid-February start of renewable—or green—electricity deliveries that will amount to about 26 million kw-hr/year, NNOS’ Nizhny Novgorod refinery has become LUKOIL’s second production plant to use power generated by renewable energy sources (RES) at the Volgograd SPP, Stavropol Region, LUKOIL said in a release.

Use of renewable power generation at the Nizhny Novgorod refinery will allow NNOS to lower the carbon footprint of its finished products by reducing indirect carbon emissions at the site by about 10,000 tpy, according to the operator.

First commissioned in 2018, the Volgograd SPP previously began supplying 11 million kw-hr/year of green electricity to LUKOIL subsidiary Stavrolen LLC’s petrochemical complex in Budennovsk, Stavropol Region, Russia, in October 2021.


ExxonMobil signs P’nyang LNG project agreement

ExxonMobil and the Independent State of Papua New Guinea have signed the P’nyang project gas agreement for the proposed development of the P’nyang LNG project in the Western Province of Papua New Guinea (OGJ Online, Feb. 24, 2020). The project is within Petroleum Retention License 3 and covers 105,000 acres (425 sq km).

The P’nyang development is proposed to commence following the Papua LNG project in Gulf Province. It is expected to deliver LNG through construction of new upstream facilities in Western Province linked to existing infrastructure, including the PNG LNG plant near Port Moresby. The agreement provides the fiscal framework for the project and supports project scoping and evaluation.

Upon completion, up to 5% of P’nyang gas produced would also be made available to support the government’s electrification efforts in Western Province or another agreed location.

P’nyang field is estimated to hold 4.36 tcf of gas.

ExxonMobil subsidiary Esso PNG P’nyang Ltd. is operator of P’nyang field. Esso PNG P’nyang, together with Ampolex (Papua New Guinea) Ltd., holds 49% interest in the license. Partners are Santos Ltd. (38.5%), and JX Nippon Oil & Energy Corp. (12.5%).

IEASA tenders for Vaca Muerta gas pipeline

State-owned Integracion Energetica Argentina SA (IEASA) has tendered for pipe to build the 656-km first stage of its Vaca Muerta natural gas transmission pipeline. Stage 1 would carry roughly 850 MMcfd from Neuquen province through Buenos Aires province north to Santa Fe by end-2023.

The pipeline’s full capacity would be 1.5 bcfd, attained through modifications to, and interconnection with, the existing Gasoducto Norte.

Vaca Muerta shale has technically recoverable reserves of 308 tcf of gas and 16 billion bbl of crude oil. It is geographically comparable with Eagle Ford shale in southern Texas. Production as of December 2020 was 900 MMcfd of gas and 124,000 b/d of oil.

Companies producing in the area include state-YPF SA, Tecpetrol, Chevron, Shell PLC, Pan American Energy LLC, Vista Oil & Gas SAB, ExxonMobil, and Pluspetrol SA. Vista earlier this year acquired Wintershall DEA Argentina SA’s 50% operating interest in Aguada Federal and Bandurria Norte blocks, the 25,231 net acres giving it 100% ownership of the blocks and increasing its total Vaca Muerta acreage to 183,084.

Cheniere expands EOG gas-supply agreement

Cheniere Energy Inc. subsidiary Cheniere Corpus Christi Liquefaction Stage III LLC (CCL Stage III) has amended the long-term integrated production marketing (IPM) gas supply agreement it signed in 2019 with EOG Resources Inc., extending its term and tripling its volume.

Under the amended IPM transaction, EOG agreed to sell 420 MMcfd to Cheniere for 15 years, with one third of the supply targeted to start upon completion of each of Trains 1, 4, and 5 of the Corpus Christi Stage III project. The LNG associated with this gas supply, about 2.55 million tonnes/year (tpy), will be owned and marketed by Cheniere, and EOG will receive a price based on the Platts Japan Korea Marker (JKM).

The earlier gas supply agreement, under which EOG will sell 300 MMcfd to Cheniere at a price indexed to Henry Hub, has also been extended to 15 years. EOG will supply a total of 720 MMcfd to CCL Stage III under the amended agreements for 15 years upon start-up of the project.

EOG will continue to sell 140 MMcfd to Corpus Christi Liquefaction LLC, which commenced in 2020, until the amended long-term agreements start. LNG associated with this gas supply, 850,000 tpy, is owned and marketed by Cheniere, and EOG receives a price based on JKM for the gas.

CCL Stage III will include seven midscale liquefaction trains with a total expected nominal production capacity exceeding 10 million tpy.

Cheniere anticipates taking final investment decision on CCL Stage III in 2022. The project would bring Corpus Christi LNG’s total capacity to 25 million tpy.