OGJ Newsletter
GENERAL INTEREST Quick Takes
Neptune progresses potential North Sea CCS project
Neptune Energy, ExxonMobil subsidiary XTO Netherlands Ltd., Rosewood Exploration Ltd., and EBN Capital BV signed a cooperation agreement to progress the L10 large-scale offshore carbon capture and storage (CCS) project in the Dutch North Sea.
This stage of the Neptune-operated project has the potential to store 4-5 million tonnes/year of carbon dioxide (CO2) for industrial customers within depleted gas fields around the Neptune-operated L10-A, B, and E areas. It represents the first stage in the potential development of the greater L10 area as a large-volume CO2 storage reservoir, the companies said in a joint statement June 20.
The company plans to have the project FEED-ready by yearend, followed by submission of a storage license application. A final investment decision is due in 2023. First carbon injection could be in 2026.
Exploratory discussions with industrial emitters from various sectors are continuing, the companies said.
BW Energy acquires clusters offshore Brazil
BW Energy’s acquisition of Golfinho and Camarupim clusters, and interest in exploration block BM-ES-23, offshore Brazil, has been approved by the Petrobras executive board.
Golfinho cluster lies in Espírito Santo basin, adjacent to BM-ES-23, which holds the Brigadeiro gas and condensate discovery. Water depths are 1,300-2,200 m. The cluster has proven low risk in-field development opportunities, BW Energy said in a release June 23.
The Camarupim cluster is also adjacent to BM-ES-23 in 100-1,050 m of water. It comprises non-producing Camarupim and Camarupim Norte gas fields.
BW Energy will acquire 100% operated working interest in Golfinho and Camarupim clusters and 65% interest in BM-ES-23 for initial cash consideration of $3 million at signing and $12 million at closing, which expected in first-quarter 2023.
The company has also agreed to contingent payments of up to $60 million after closing tied to oil price and production volume.
The acquisition is expected to add about 9,000 b/d oil production from early 2023.
BW Energy will be the operator in all concessions. PTTEP (20%) and Inpex (15%) will be partners in BM-ES-23.
Lebanon extends deadline for second offshore licensing round
Lebanese authorities have extended the deadline for oil and gas companies to submit bids for open blocks in the Second Offshore Licensing Round to Dec. 15, 2022.
The extension, issued by the Minister of Energy and Water on June 15 (the previous deadline), was granted following a request by the Lebanese Petroleum Administration to allow more time for companies not currently operating offshore Lebanon to prepare files and studies “allowing an acceptable level of competition among the international oil and gas companies,” a statement from energy minister said.
There are eight blocks on offer: 1, 2, 3, 5, 6, 7, 8, and 10.
Blocks 4 and 9 were previously awarded to a consortium of TotalEnergies (operator, 40%), Eni SPA (40%), and OAO Novatek (20%). Both blocks are in water depths of 1,400-1,800 m. The consortium drilled well 16/1, the first exploration well on Block 4 in 2020, targeting the Lower Miocene in water depth of 1,515 m. Plans for a well on Block 9 have been delayed due to an ongoing border dispute with Israel.
Exploration & Development Quick Takes
TotalEnergies advances work offshore Suriname with Krabdagu flow test
TotalEnergies has advanced exploration activity on Block 58 offshore Suriname with data from the Krabdagu flow test that accelerates the company’s understanding of the field and will shape future activity, partner APA Corp., Houston, said in a release June 21.
Flow test data from the two lower intervals—the Upper Campanian and Lower Campanian—of the Krabdagu exploration well (KBD-1) indicate oil-in-place resource of about 100 million bbl and 80 million bbl, respectively.
In the Upper Campanian zone, the company encountered 32 m of net oil pay, high quality reservoir with 400-500 millidarcy permeability, 35° API, and 2,000-2,300 scf/bbl GOR.
In the Lower Campanian zone, the joint venture encountered 32 m of net oil pay, modest reservoir quality with 60-80 millidarcy permeability, 37° API, and 2,500-2,800 scf/bbl GOR.
The tests were performed in the exploration well, and appraisal drilling will be necessary to confirm additional resource and optimal development well locations, APA said. The exploration well encountered another high quality, lower GOR interval in the Upper Campanian that was not in a location suitable for flow testing. The company said this shallower Campanian zone will need to be flow tested in the appraisal stage from a more optimal location.
Results from the flow test in the two lower intervals are in line with expectations and provide data for future activity including identifying well locations to assess upside potential for each target, said John J. Christmann IV, APA chief executive officer and president. “The connected resource demonstrated from the flow tests at Krabdagu combined with the results from Sapakara South” are a step toward advancing a project in this area of the block, he said.
The joint venture is currently drilling the Dikkop exploration well in the central portion of Block 58 with the Maersk Valiant drillship. Following completion of operations, the rig is expected to continue exploration and appraisal activities in the central portion of the block.
TotalEnergies is operator with 50% interest. APA Suriname holds the other 50%.
OGDCL discovers gas at Kaleri Shum 01
Oil and Gas Development Ltd. (OGDCL), operator of the Kalchas exploration license, discovered gas at Kaleri Shum-01 in Rajanpur (Tribal area), Punjab Province, Pakistan, the company said in a release June 22.
Kaleri Shum-01 was spudded Dec. 31, 2021, to test the hydrocarbon potential of Pab, Fortmunro-Mughalkot, and Parh formations. The well was drilled to depth of 1,907 m. Based on the results of wireline logs interpretation, the operator conducted four drill stem tests (DST) in Parh, Fortmunro-Mughalkot, Pab, and Ranikot formations.
During DST-1 in Parh and Fortmunro-Mughalkot formations, the well flowed at a rate of 1.24 MMscfd through a 32/64-in. choke at well head flowing pressure of 220 psi. DST-2 into Fortmunro-Mughalkot formations tested 0.489 MMscfd through a 32/64-in. choke at well head flowing pressure of 300 psi. The well also tested 0.192 MMscfd from Pab sandstone during DST-3 through a 32/64-in. choke at well head pressure of 10-75 psi. DST-4 pf the Ranikot formation tested 0.16 MMscfd through a 32/64-in. choke at well head pressure of 100-130 psi.
OGDCL holds 50%. Mari Petroleum Co. Ltd. holds the other 50%.
ONGC Videsh discovers oil in Llanos basin, Colombia
ONGC Videsh Ltd. (OVL) discovered oil in the Urraca-IX well in CPO-5 block, Llanos basin, Colombia. The discovery in the Lower Mirador play opens new areas for further exploration in the northern part of the block, the company said in a June release.
The well spudded Apr. 20, 2022, and was drilled to target depth of 10,956 ft, encountering 17-ft thick oil-bearing sands between 10,201-10,218 ft. During initial testing with an electrical submersible pump, fluid flowed at about 600 b/d with around 40-50% water cut and 16° API oil.
ONGC Videsh discovered commercial oil in the Lower Sand pay in Mariposa and Indico fields in the block in 2017 and 2018, respectively. They are producing 20,000 b/d.
ONGC Videsh is operator with 70% inerest. Geopark Co. holds 30%.
Drilling & Production Quick Takes
Energy Resources plans appraisal wells on Lockyer Deep permits
Energy Resources Ltd. and Norwest Energy Ltd. will execute a two-well appraisal program following record gas flows at the Lockyer Deep discovery onshore North Perth basin.
The joint venture completed analysis of data gathered during the March Lockyer Deep-1 drilling and testing program, which produced an absolute open flow rate (unconstrained by tubing) estimated at 190 MMcfd, Norwest said.
Analysis suggests a 70-110 bcf gas-in-place resource within the well test maximum radius of investigation which represents an area of about 3 sq km around Lockyer Deep-1.
A two-well back-to-back drilling program across the Lockyer Deep/North Erregulla Deep structure is expected to begin in fourth-quarter 2022.
North Erregulla Deep-1 (NED-1) has been designed to test the structural high located about 8.5 km southeast of Lockyer Deep-1. NED-1 is considered an exploration well rather than appraisal because of the distance from the recent discovery and the possibility of fault compartmentalization between the two well locations.
Lockyer-2 will be down-dip and northeast of Lockyer Deep-1. It is designed to determine the down-dip presence of gas within the Kingia formation reservoir.
Lockyer-3 and Lockyer-4 are also in the planning stages. Final locations and timing will be confirmed based on results of the upcoming program, the company said.
A 385-sq km Rocco 3D seismic survey—planned to begin in December and take 4 months to complete—is expected to provide high-resolution and high-quality subsurface views of the Lockyer Deep discovery to be used as a guide for later appraisal and development drilling, as well as reserves evaluation and development planning.
Data from the Ringneck 2D seismic program completed in March are being processed. Results, expected in September, will support the coming drilling program prior to completion of the Rocco 3D survey, Norwest said.
The Lockyer Deep/North Erregulla prospects are spread across contiguous permits EP 368 and EP 426, both operated by Energy Resources. In EP 368 Energy Resources has 80% with Norwest 20%. In EP 426 Energy Resources has 77.78% and Norwest 22.22%.
Galilee completes pilot drilling in Glenaras CSG program
Galilee Energy Ltd., Brisbane, has completed the sixth and final well of the 2022 drilling program in the Glenaras multi-well coal seam gas pilot project in permit ATP 2019 in the Galilee basin of central east Queensland.
The sixth well (Glenaras-29) was drilled to a total depth of 1,039 m intersecting all target Betts Creek coal seams. A total of 27 m of net coal has now been confirmed containing strong gas shows, the company said.
Completion marks the end of the drilling component of the overall Glenaras program.
Galilee took 100% ownership of the Glenaras gas project in 2015 and has been working to prove up the potential of the coal seams as a major gas supply.
The project has independently derived and certified contingent resources within the Betts Creek coals of 308 petajoules (1C), 2,508 petajoules (2C), and 5,314 petajoules (3C).
Drilling has been designed to accelerate depressurization of the coals and initiate gas desorption.
Earlier pilot wells were fracture stimulated which opened underlying sandstones to production. The pilots produced high water rates, but much of the water came from sandstones and thus the coals were not sufficiently depressured to achieve desorption and subsequent gas production.
The new approach has been to drill the pilot wells to 1,000 m without penetrating the sandstone units, case them to the top of the coal section, and leave the Betts Creek beds as an open-hole completion.
All existing wells are being brought back online with work on the surface infrastructure expected to be completed by end July 2022, the company said.
Equinor plugs dry well near Kvitebjørn field
Equinor Energy AS has plugged a North Sea exploration well following drilling that encountered the Sola formation, but reservoir rocks in the form of sandstone were not present. The well is dry.
Exploration well 34/9-1 S (Cambozola prospect), the first exploration in production license 1049, was drilled by Odfjell Drilling’s semi-submersible drilling rig, about 35 km northeast of Kvitebjørn field in the North Sea and 167 km northwest of Bergen to a vertical depth of 4,393 m subsea. The well was terminated in the Sola formation in the Lower Cretaceous. Water depth at the site is 382 m.
The objective was to prove petroleum in Lower Cretaceous reservoir rocks (the Sola formation in the Cromer Knoll group).
Data acquisition was carried out.
Equinor is operator of the license with 35% interest. Partners are Longboat Energy Norge AS (25%), Petoro AS (20%), and Sval Energi AS (20%).
The rig is moving to drill well 30/3-11 S (Poseidon prospect) in production license 1104 in the northern North Sea, where Equinor is operator.
PROCESSING Quick Takes
EIA: Global surplus crude oil production capacity decreases in 2022
The result of declines in surplus production capacity in both OPEC and non-OPEC countries, global surplus crude oil production capacity in May 2022 was less than half its 2021 average, the US Energy Information Administration said in a report.
The report, Global Surplus Crude Oil Production Capacity, provides estimates of global surplus crude oil production capacity in both OPEC countries and non-OPEC countries. As of May 2022, surplus capacity in non-OPEC countries decreased by 80% compared with 2021, according to EIA’s preliminary estimates. In 2021, 1.4 million b/d of surplus production capacity was available in non-OPEC countries, about 60% of which was in Russia.
EIA estimates that all surplus production capacity in Russia was eliminated as of May 2022 due to the sanctions implemented after Russia’s full-scale invasion of Ukraine. EIA determined that excess oil production capacity declined in other non-OPEC producing countries as well. As of May 2022, producers in non-OPEC countries had about 280,000 b/d of surplus production capacity.
“We define surplus capacity as the maximum existing capacity that can be brought online within 30 days and sustained for at least 90 days. Our assessment of surplus crude oil production capacity does not include volumes of oil that are offline because of unplanned outages and disruptions, including sanctions, because these volumes cannot be brought to market voluntarily. For that reason, we exclude crude oil production that is offline in Iran, Libya, Venezuela, and now Russia, from surplus capacity estimates,” EIA explained.
Since 2003, EIA has tracked OPEC surplus capacity in a separate publication, the Short-Term Energy Outlook (STEO). EIA defines OPEC in terms of its current membership.
In its June STEO, EIA estimated that OPEC surplus capacity declined to 3 million b/d by May 2022 from 5.4 million b/d in 2021.
ExxonMobil advances upgrading at Singapore complex
ExxonMobil Corp. is targeting startup of its multibillion-dollar upgrading project that will convert fuel oil and other bottom-of-the-barrel crude products into higher-value lube base stocks and distillates at subsidiary ExxonMobil Asia Pacific Pte. Ltd.’s Singapore integrated manufacturing complex in 2025.
The project will add 20,000 b/d of light, heavy, and extra-heavy Group II base stocks capacity, including EHC 50 and EHC 120, as well as equip the complex with proprietary technologies for production of up to 6,000 b/d of extra-heavy base stocks, including the new high-viscosity EHC 340 MAX Group II base stock to help meet the Asia Pacific’s growing lubricant demand, ExxonMobil said on June 22.
The project also will expand capacity to increase production of cleaner, ultralow-sulfur fuels and fuel-blending components, and high-quality marine fuels to enable customers to meet the International Maritime Organization’s 0.5% sulfur emission control area requirements, the operator said.
Previously scheduled for startup in 2023, the Singapore upgrade and expansion—like most large-scale industrial projects—experienced construction delays resulting from the pandemic.
IEA: Global refinery capacity increases gather pace in 2023
After posting its first decline in 30 years during 2021, global refining capacity will increase 1 million b/d this year and a further 1.6 million b/d in 2023, the International Energy Agency (IEA) said. This is a result of 4.1 million b/d of new capacity coming online, offset by 1.6 million b/d of permanent shutdowns.
The closures are front-loaded, with 1.1 million b/d set to shut in 2022. Still, the pace of capacity shutdowns is slowing somewhat, compared to 1.8 million b/d in 2021. Over 2022 and 2023, net capacity growth is slightly less than in 2019, but is among the fastest rates for net additions observed over the last two decades, according to IEA data.
East of Suez delivers 70% of global net additions in 2022-23, led by major projects in the Middle East and China. After 4 years of capacity decline, the Atlantic Basin will finally see net growth, thanks to African and North American projects.
“When looking at a 5-year period of 2019-23, the role of East of Suez is even more prominent—it delivers all the growth globally, offsetting the net 700,000 b/d decline in the Atlantic Basin. China alone accounts for almost 70% of global net additions in 2019-2023, even as the rate of the capacity additions in the country slows in 2022-23. Excluding China, global capacity additions during 2019-2023 amount to just 1 million b/d,” IEA said.
Among additions, 2.8 million b/d are greenfield sites, while the rest is expansion projects at existing refineries. Five projects, including mega-refineries in Nigeria and Kuwait and large sites in China and Mexico, contribute 2.3 million b/d, which is just over half of total gross additions.
“Assumed start-up dates for these particularly big projects mostly reflect the initial launch of the first train where the projects consist of several trains. There is also the usual degree of uncertainty around the start-up dates due to operational issues, logistical challenges, and supply chain disruptions, among other various unforeseen circumstances affecting the planned timing of projects,” IEA said.
IEA has not included the recent announcement of Japanese refiner Idemitsu Kosan on shutting the 120,000 b/d Yamaguchi refinery by end FY2023, as the timeline extends into 2024 due to the fiscal year ending in March.
TRANSPORTATION Quick Takes
Cheniere sanctions CCL Stage III, signs LNG deals with Chevron
Cheniere Energy Inc. has made a positive financial investment decision (FID) to proceed the 10 million tonnes/year (tpy) Corpus Christi Stage III liquefaction project (CCL Stage III) and has issued full notice to proceed to Bechtel Energy Inc. to continue construction, which began earlier this year under limited notice to proceed.
The fully permitted project consists of up to seven midscale trains, each with an expected liquefaction capacity of about 1.49 million tpy with a total production capacity over 10 million tpy, bringing Corpus Christi LNG’s total capacity to 25 million tpy. The project is expected to begin providing customers with LNG by end 2025.
Separately, two Cheniere subsidiaries, Sabine Pass Liquefaction LLC (SPL) and Cheniere Marketing LLC, each entered into long-term LNG agreements with Chevron USA Inc. At plateau, Chevron will purchase a combined 2 million tpy of LNG from Cheniere subsidiaries, subject to conditions.
Under the first agreement, Chevron agreed to purchase about 1 million tpy of LNG from SPL on a free-on-board basis. Deliveries will begin in 2026, reach the full 1 million tpy in 2027, and continue until mid-2042.
In the second deal, Chevron agreed to purchase about 1 million tpy of LNG from Cheniere Marketing on an a free-on-board basis with deliveries beginning in 2027 and continuing for about 15 years. The agreement is subject to Cheniere making a positive FID to construct additional liquefaction capacity at the Corpus Christi LNG terminal beyond the seven-train CCL Stage III project. The purchase price is indexed to Henry Hub, plus a fixed liquefaction fee.
Additionally, Cheniere subsidiary Sabine Pass LNG LP and Chevron agreed to terms for early termination of their LNG terminal use agreement in return for a lump sum payment by Chevron in calendar year 2022. Termination, expected in third-quarter 2022, is subject to consent of certain lenders.
Feed gas introduced to Coral Sul FLNG
Eni SPA, upstream operator of Area 4 offshore Mozambique, introduced natural gas from the 16-tcf Coral South reservoir to the 3.4-million tonne/year Coral Sul floating LNG (FLNG) plant. Coral Sul will load its first LNG cargo in second-half 2022, Eni said.
The FLNG arrived offshore Mozambique in January, was moored at 2,000-m water depths over Rovuma basin in March and connected to six underwater production wells in May.
Eni’s (35.7%) partners in Coral South are ExxonMobil Corp. (35.7%), China National Petroleum Corp. (28.6%), Galp Energia SGPS SA (10%), Korea Gas Corp. (10%), and state-owned Empresa Nacional de Hidrocarbonetos de Mozambique EP (10%).