GENERAL INTEREST Quick Takes
Australian government wants to extend gas price cap
The Australian government’s control on gas prices is set to be extended a further 18 months until mid-2025 as outlined in a draft code of conduct for the gas industry released Apr. 26.
The government set a temporary A$12 per gigajoule limit on gas in December 2022 after it received Treasury warnings that energy prices were set to soar upward by as much as 50% during 2023 and into 2024.
The government now wants to establish a code of conduct to begin in 2024 which, it says, will ensure sufficient supply of Australian gas for Australian domestic users at reasonable prices while still giving producers the certainty they need to invest in supply.
The draft code proposes to extend the existing cap until July 2025.
It also introduces a range of exemptions for smaller gas producers that only supply gas for domestic use as well as for any larger producers who commit to tightly defined enforceable undertakings to produce and supply gas into the domestic market at a reasonable price ahead of time.
It would also ensure Australia remained a reliable trading partner by enabling LNG producers to meet their export commitments, the government said.
Energy Minister Chris Bowen said the aim is to ensure that producers do not revert to earlier unregulated export practice at yearend.
Europe’s LNG hunger continues, imports from Russia remain high
With the summer injection season under way, Europe’s gas storage levels are near the top of the 5-year average, and gas injection continues. The US remains Europe’s leading LNG exporter, while Russia, the third-largest supplier, continues to deliver strong volumes.
LNG flows from Russia into Europe have been steady, according to Rystad Energy, with recent flows of 77 million cu m/d (MMcmd) through Ukrainian transit and the Turk Stream infrastructure. February 2023 was a record month for Russian LNG shipments to Europe—1.61 million tonnes, equivalent to 17% of the total LNG volume.
Currently, EU sanctions do not prohibit Russia from exporting LNG to Europe, but individual buyers may actively avoid purchases, such as Germany’s new floating storage and regasification units (FSRUs), which would avoid Russian LNG deliveries.
Meantime, supply from Norwegian flows has held steady. Output from the Norwegian Continental Shelf (NCS) totaled 386.39 MMcmd on Apr. 25, despite multiple ongoing outages at Troll, Kollsnes, Karsto, and Ormen Lange. The Norwegian private industry workers’ strike came to an end Apr. 20.
EU’s storage infrastructure is currently about 58% full, according to the latest confirmed data from AGSI (Aggregated Gas Storage Inventory) on Apr. 24. On a country level, UK storage is 57.3% full, France is at 33%, and Germany sits at 65.7%.
Gas prices are holding steady at $12.92/MMbtu on the Netherlands-based Title Transfer Facility (TTF) on Apr. 25, a weekly decrease of 6%.
US natural gas storage 19% above average as of March
Working natural gas in storage in the US at end-March—generally considered the end of the US storage withdrawal season (November-March)—reached 1,856 bcf, 19% above the 5-year (2018-2022) average, according to estimates from the US Energy Information Administration (EIA).
Higher US natural gas storage reflects below-average natural gas withdrawals from storage during first-quarter 2023, which also leads to lower natural gas prices. Henry Hub natural gas spot prices averaged $5.45 per MMbtu in November 2022, falling to an average of $2.31/MMbtu in March.
Assuming summer injections are similar to the 5-year average, this year’s end-October natural gas inventories would sit 8% above last year’s end-October inventories and 6% above the 5-year average.
According to EIA data, US dry natural gas production averaged 101.6 bcfd in first-quarter 2023, up 1.4% from fourth-quarter 2022, thanks to mild weather and the absence of major interruptions. Associated natural gas production in the Permian basin and production in the Haynesville region set new records in early 2023, driving growth in US natural gas production in the quarter. However, US natural gas production would decline slightly in April and May due to pipeline maintenance in West Texas and the Northeast.
Over the summer, as Freeport LNG resumes full operations, and power sector gas consumption increases, combined with relatively flat US gas production, natural gas prices could rise slightly above $3/MMbtu.
Exploration & Development Quick Takes
Wintershall Dea makes discovery offshore Mexico
Wintershall Dea and partners made a significant oil discovery on the Kan exploration prospect in Block 30 in the shallow water of the Cuenca Salina in Sureste basin, about 25 km offshore Mexico. Based on preliminary estimates, the discovery may contain 200-300 MMboe in place.
Kan, the first of two commitment wells on the block, lies in water depth of about 50 m within a zone of several Miocene discoveries including Zama, Polok, and Chinwol.
Kan-1EXP, drilled by the Borr Ran jack up unit, reached a total depth of 3,317 m and found more than 170 m net pay sands of Upper Miocene with good petrophysical properties and high-quality oil. An updip sidetrack down to 3,087 m was carried out, and about 250 m of core across the main reservoir sands were recovered.
The Block 30 consortium will evaluate the extensive subsurface data collection to prepare a discovery appraisal plan to be submitted to Mexico’s Hydrocarbon Agency Comisión Nacional de Hidrocarburos (CNH) before end-July 2023.
The drilling rig has moved to Ix, a second prospect to be drilled at Block 30 about 20 km northeast of the Kan discovery.
Wintershall is operator at Block 30 with 40% interest. Partners are Harbour Energy (30%) and Sapura OMV (30%).
OMV to evaluate volume potential of North Sea oil discovery near Gudrun field
OMV (Norge) AS and partners will evaluate an oil discovery in North Sea production license 817 to define the volume potential in different reservoir zones and assess the discovery alongside other prospects in the area, the Norwegian Petroleum Directorate said in a release Apr. 20.
Exploration well 15/2-2 S, the first in the license, was drilled by the Deepsea Yantai drilling rig about 5 km west of Gudrun field and about 230 km west of Stavanger in water depth of 111 m. The well was drilled to a vertical depth of 4,723 m subsea. It was terminated in the Draupne formation in the Upper Jurassic.
The objective was to prove petroleum in reservoir rocks in the intra-Draupne formation from the Upper Jurassic. The well encountered the 500-m-thick intra-Draupne formation, consisting of multiple thin sandstone layers totaling 23 m with poor reservoir properties.
The well was not formation-tested, but data acquisition and sampling were undertaken.
Oil samples were taken from two different sand layers with different pressure regimes. Oil shows were also registered throughout the entire interval in the Upper Jurassic. It will now be permanently plugged.
Due to the limited thickness of the sandstone layers and uncertainty in their dispersion, the preliminary estimate of the size of the discovery is 0.95-5.55 million standard cu m of recoverable oil equivalent.
OMV (Norge) AS is operator of the license with 50% interest. Partners are Neptune Energy Norge AS (30%) and Source Energy AS (20%).
Energy Resources downgrades Lockyer-2 following appraisal
Energy Resources Ltd. has found the primary Kingia Sandstone target in its Lockyer-2 appraisal well onshore North Perth basin of Western Australia to be water saturated despite the reservoir being of high quality. The result considerably downgrades the resource potential of the Greater Lockyer structure.
The well, about 3.2 km northeast of the Lockyer Deep-1 gas discovery in permit EP368, reached a total depth of 4,574 m.
Low levels of background gas were noted in the reservoir, but analysis of wireline data and sampling indicated that the aquifer is at a much higher pressure than previously interpreted.
The anomalously high pressure indicates a much-reduced gas column with the free water line now interpreted to be at a depth of 4,007 m.
The Kingia target was intersected at 4,142 m depth in Lockyer-2 and the potential resource area (above the free water line) is now estimated by JV partner Norwest Energy to be around 11 sq km.
Norwest said the secondary targets within the Dongara, Wagina, and High Cliff formations were also found to be water saturated.
Forward plans are to obtain rotary sidewall cores and run a velocity survey via wireline techniques before suspending the well for potential future use. The will move to drill the group’s North Erregulla Deep-1 well.
Energy Resources, a subsidiary of Mineral Resources Ltd., is 80% interest holder and operator. Norwest holds the remaining 20%.
Mineral Resources launched a takeover bid for Norwest in 2022 and currently holds over 76% interest in its JV partner.
Drilling & Production Quick Takes
Vår Energi expects to deliver 50% production growth over next 3 years
Vår Energi ASA expects to deliver more than 50% production growth over the next 3 years, with development projects underpinning its end-2025 production target above 350,000 boe/d progressing to plan, the company said in a release Apr. 24.
Aker BP-operated Frosk (Vår Energi 20%), in the North Sea, came online in first-quarter 2023, while Equinor-operated Bauge and Hyme developments in the Norwegian Sea came online early in this year’s second quarter. Production at Fenja is expected on stream later in this year’s second quarter, the company said.
First oil at Equinor-operated Breidablikk (Var Energi 34.4%) in the North Sea is expected in first-quarter 2024. Balder X, where Var Energi in September 2022 added $1.2 billion to the Norwegian Continental Shelf project’s cost and delayed first oil, is still on track for startup in third-quarter 2024. Equinor-operated Johan Castberg (Var Energi 30%) is on track for first oil in fourth-quarter 2024.
Production for first-quarter 2023 came in at 214,000 boe/d, stable from fourth-quarter 2022, the company said. Full year 2023 production guidance is unchanged at 210,000-230,000 boe/d.
Norway production up in March, NPD says
Norway’s production averaged 2.049 million bbl in March, the Norwegian Petroleum Directorate (NPD) reported. The figure is up from the 1.994 million bbl produced in February.
Average daily liquids production in March consists of 1.826 million b/o, 201,000 bbl of NGL, and 23,000 bbl of condensate.
Oil production in March is 0.1% higher than the NPD’s forecast and 1.7% lower than the forecast so far this year.
Rhein Petroleum to spud Erfelden field well, southwest Germany
Rhein Petroleum GmbH, a subsidiary of Beacon Energy PLC, has let a contract to RED Drilling & Services GmbH for a fully crewed drilling rig for the Schwarzbach-2 development well in Erfelden field, onshore southwest Germany.
The rig is expected to mobilize in early-June 2023. The well, expected to be spudded mid-June, is targeting the Stockstadt Mitte segment which was proven by the Stockstadt Mitte-1 well (SK-M1) drilled by Exxon in 1986. This well encountered oil in the PBS sandstones and in the shallower Meletta-Schichten sands (ME).
Drilling operations are expected to take 25 days to reach 2,255m TD (1,709 m TVD), with an additional 12 days scheduled for testing. The drilling pad has been prepared and the 20-in. conductor pipe has been set at 85 m.
Once completed, the well will be tied-in to existing production equipment at the Schwarzbach production site which will take about 12 days to complete.
Schwarzbach-2 is the first of potentially two development wells and one water well to be drilled in the Stockstadt Mitte segment over the next 18 months, the company said.
Erfelden oilfield is the most northern oil field in the Upper Rhine Graben and is comprised of four juxtaposed structural segments: the depleted Kuehkopf segment, the producing Schwarzbach Main segment, the discovered Stockstadt Mitte segment, and the unproven Schwarzbach South segment.
The Stockstadt Mitte segment contains 2P reserves of 3.784 million bbl. The Schwarzbach South segment is undrilled, with 2C contingent resources of 2.4 million bbl. This segment will be the target of future development drilling.
Rhein Petroleum is operator and owns 100% of Erfelden field.
PROCESSING Quick Takes
Petrobras plans capacity increase at RNEST refinery
Petrobras let a contract for the proposed modernization of existing units at Train 1 of the operator’s original nameplate-capacity 130,000-b/d Refinaria Abreu e Lima (RNEST) refinery in Ipojuca, Pernambuco, in northeast Brazil.
Signed on Apr. 20, the contract covers works to improve operations of RNEST Train 1’s atmospheric distillation unit, delayed coker, and other unidentified auxiliary units that, together, will return Train 1’s total crude oil processing capacity to 130,000 b/d from a current 115,000 b/d, Petrobras said.
The operator revealed neither the value nor the recipient of the contract.
Scheduled for completion during fourth-quarter 2024 and included in the company’s 2023-27 strategic plan, the proposed modernization also will enable Petrobras to increase its supply of 100% low-sulfur Diesel S10 for the Brazilian market beginning in 2025.
In addition to reducing emissions of particulate matter, use of Diesel S10—which has a higher cetane number than Diesel S500 (500 ppm sulfur)—promotes improved fuel performance of vehicle engines in line with Brazil’s stricter air pollution control program for on-road heavy-duty and utility vehicles (OGJ Online, June 15, 2022).
The operator’s 2023-27 strategic plan also includes the proposed completion and expansion of RNEST’s previously stalled Train 2, which has the potential to double the refinery’s capacity to 260,000 b/d with startup of the second 130,000-b/d processing train.
Planned modernization of RNEST Train 1 follows the operator’s August 2022 restart of the nonbinding phase in its program to sell three of its Brazilian refineries and associated logistics assets, the sales of which were previously delayed to accommodate revisions to divestment plans for each of the sites that, alongside RNEST, include the 208,000-b/d Refinaria Presidente Getulio Vargas (REPAR) refinery; and 208,000-b/d Refinaria Alberto Pasqualini (REFAP) refinery.
Petrobras previously said upon initially delaying the sales process in August 2021 that it would evaluate next steps regarding RNEST’s future after completing internal procedures to end the refinery’s then-current sale process.
With a rated crude processing capacity of 88,000 b/d as of yearend 2022, RNEST’s average throughputs—including crude and NGL feedstock—have decreased to 61,000 b/d in 2022 from 93,000 b/d, according to Petrobras’ latest annual report to investors.
Strike completes initial engineering for modular South Erregulla gas plant
Strike Energy Ltd., Perth, has completed initial engineering with Technip Energies for a low-cost modular and expandable gas plant to be sited at the company’s Mid-West Low Carbon Manufacturing Precinct linked to commissioning of South Erregulla gas field in late 2024.
The development proposal entails three phases:
- An initial 40 terajoules/day modular plant to support production from the existing 128 petajoules of 2P reserves.
- A Phase 2 addition of expansion modules to bring throughput up to 80 terajoules/day following booking of additional reserves from an appraisal drilling program.
- A Phase 3 of additional deployment of CO2-removal modules to support development of the precinct’s carbon sequestration, and inclusion of compression and integration of the Precinct’s wind and solar capacity.
The field and precinct lie within onshore North Perth basin permit EP503.
The proposed prefabricated modules will reduce construction times, ease supply chain issues, and facilitate a fast-commissioning process through off-site pre-commissioning activities prior to module delivery, Strike said.
The company is continuing engineering of the gas plant and has begun engagement with potential suppliers for the engineering, procurement, and fabrication contract for the modular plant.
Strike submitted its primary environmental approval for the field, plant, and pipeline, as well as the production licence application and field management plan.
The company is also preparing a three-well drilling campaign that will include two westerly updip appraisal wells targeting the Kingia reservoir and an easterly Wagina reservoir appraisal well.
Drilling is expected to begin in July with the aim of converting 271 petajoules of contingent 2C resources to 2P reserves.
TRANSPORTATION Quick Takes
Permian Highway expansion in-service date slips, KMI earnings up 2%
The in-service date for Kinder Morgan Inc.’s (KMI) 550-MMcfd expansion of the Permian Highway (PHP) natural gas pipeline has slipped to December 2023, with KMI attributing the delay to supply-chain constraints.
The 2.1-bcfd PHP, owned by KMI, Kinetik Holdings Inc., and ExxonMobil Corp., ships gas 430 miles from the Waha area in the Permian basin to the US Gulf Coast. The expansion was originally expected to have entered service Nov. 1, 2023.
Work is under way on all three of the compressor stations involved in Tennessee Gas Pipeline’s (TGP) $263-million, 115-MMcfd East 300 upgrade project. TGP is adding gas-fired compression at two of the stations and in February began building the third, a 19,000 electric-driven unit in West Milford, NJ. The company has entered a long-term, binding agreement with Consolidated Edison Co. of New York Inc. to supply the additional gas to its distribution system. Pending receipt of all required permits, the project has an expected in-service date of Nov. 1, 2023.
Permitting has begun for a $180-million TGP project to build a new 32-mile, 30-in OD pipeline that will ship 245-MMcfd gas from the existing TGP system to Tennessee Valley Authority’s proposed 1,450-Mw powerplant at an existing site in Cumberland, Tenn. Pending permits and clearances, the project is expected to enter service Sept. 1, 2025.
Earnings, operations
KMI had first-quarter 2023 net income of $679 million, compared with $667 million in first-quarter 2022. Natural gas transport volumes were up 3% compared with first-quarter 2022, primarily due to increases on El Paso Natural Gas driven by Line 2000’s return to service, cooler weather, and the retirement of a coal-fired power plant. Gas gathering volumes were up 18% year-on-year, gains coming primarily from KMI’s Haynesville and Eagle Ford systems.
Crude and condensate volumes, by contrast, were down 5%, with unfavorable basis differentials hindering shipments on the 84,000-b/d Double H pipeline. The crude and condensate business was also impacted by lower Eagle Ford shale recontracting rates.
Refined products volumes were flat compared with first-quarter 2022. Gasoline volumes were up 1% year-on-year and diesel volumes were down 11%. Jet fuel volumes continued their strong rebound, up 12% versus first-quarter 2022.
Tellurian gets FERC permission to build Driftwood Line 200-300 system
Tellurian Inc. received US Federal Energy Regulatory Commission authorization for Driftwood Pipeline LLC’s Line 200 and Line 300 projects in Beauregard and Calcasieu Parishes, La. The 37-mile, dual 42-in. OD natural gas pipelines’ combined capacity will be more than 5.5 bcfd.
The $1.4-billion gas transmission project will be virtually emissions free, according to Tellurian, due to use of electric-powered integrated compressor line technology from Baker Hughes Co.
Tellurian in April agreed to sell about 800 acres on which it is building part of its 27.6-million tonne/year Driftwood LNG plant, signing a letter of intent with an unnamed New York-based firm to have the investor buy the land in Lake Charles, La., for $1 billion and then lease it back to Houston-based Tellurian for 40 years. Bechtel Energy Inc. began construction of Driftwood Phase 1 on the site in fourth-quarter 2022.
Tellurian produced 225 MMcfd of gas in fourth-quarter 2022, up from 55 MMcfd a year earlier, putting 13 Haynesville shale wells in production that quarter. The company’s total proved reserves at end-2022 were 445 bcf, a year-on-year increase of more than 100 bcf.