GENERAL INTEREST Quick Takes
Denbury expands CO2 sequestration portfolio in Louisiana
Denbury Inc. has signed agreements that will expand the company’s carbon dioxide sequestration portfolio in Louisiana.
The company signed an agreement with Lapis Energy LP to form a joint venture to design, implement, and operate a CO2 sequestration project at Lapis Energy’s 14,000-acre site in St. Charles Parish, La., about 20 miles west of New Orleans.
Each party will have a 50% interest in a newly formed project company, Libra CO2 Storage Solutions LLC. The partners believe that the site could potentially store at least 200 million metric tons of CO2. The site, near industrial infrastructure, could be ready for first injection as early as 2027.
Depending on the scale and pace of emissions agreements dedicated to the site, Denbury said it intends to connect the site to its existing CO2 pipeline network in southeast Louisiana with a 45-mile pipeline connection.
In a separate agreement with Soterra LLC, a wholly owned subsidiary of Greif Inc., Denbury acquires rights to develop a dedicated CO2 sequestration site on 8,500 acres in St. Helena Parish, about 50 miles northeast of Baton Rouge, La., and less than 5 miles from the company’s NEJD CO2 pipeline.
Denbury estimates potential CO2 sequestration capacity of the site (Virgo) to be at least 100 million metric tons and anticipates the site could be ready for first CO2 injection as early as 2026.
With the additions, Denbury expands its CO2 sequestration sites to 10, including sites in Alabama, Louisiana, Mississippi, Texas, and Wyoming, and a total potential storage volume of about 2 billion metric tons of CO2.
In June 2023, Denbury was informed by the US Environmental Protection Agency that it had deemed the company’s Class VI storage permits (up to 6 CO2 injection wells) over the Leo site in Mississippi “technically complete.”
As part of its Class VI permitting program and to advance efforts to provide CO2 sequestration by end-2025, Denbury plans to submit Class VI permits to the EPA covering 2-3 additional dedicated sequestration sites this year.
Denbury intends to drill 2-3 additional stratigraphic test wells across its portfolio by end-2023.
Baytex updates guidance post-Ranger acquisition close
Baytex Energy Corp., Calgary, has updated its 2023 guidance and closed its $2.2 billion acquisition of Ranger Oil Corp.
The company expects to have 34 net wells onstream in the Eagle Ford and 90 net wells onstream in Western Canada in this year’s second half.
The acquisition increased the scale of the company’s Eagle Ford operations, adding 162,000 net acres in the play’s crude oil window, on-trend with Baytex’s non-operated position in the Karnes Trough, and 741 net undrilled locations, representing an inventory life of 12-15 years, the company said (OGJ Online, Feb. 28, 2023).
Average production for second-quarter 2023 is estimated at 88,500-89,000 boe/d, which includes production from Ranger for the 11 days following closing of the acquisition.
Production in the quarter was reduced by about 4,500 boe/d due to the temporary curtailment of production resulting from the wildfires in Alberta (OGJ Online, May 30, 2023).
For second-half 2023, exploration and development expenditures are forecast to be $595-635 million, which are expected to generate an average production rate of 153,000-157,000 boe/d. The year’s second-half production mix is forecast to be 84% oil and NGLs (50% light oil, 22% heavy oil, 12% NGLs) and 16% natural gas.
Vitol’s VTX to add to southern Delaware basin acreage position
Vitol Inc.’s US upstream company, VTX Energy Partners LLC, agreed to acquire 12,000 net leasehold acres in the Delaware basin. Neither the purchase price nor the seller was disclosed.
The deal comes on the heels of the company’s initial acquisition, that of Delaware Basin Resources, announced in January (OGJ Online, Jan. 19, 2023).
The latest deal, which Vitol says includes acres contiguous to its first deal and current daily production of about 4,000 boe/d, brings the company’s total southern Delaware basin position to 47,000 net acres. The newly acquired assets also include associated water infrastructure.
VTX Energy Partners is the successor company to ATX Energy Partners, an Austin-based oil and gas company pursuing an acquisition and development strategy in the US Lower 48. Vitol described VTX as a complement to Vencer Energy, Vitol’s existing upstream partnership in the Midland basin.
Chevron Australia completes Thevenard Island decommissioning
Chevron Australia has completed onshore decommissioning works at Thevenard Island which houses the Chevron-operated Thevenard Island joint venture oil and gas site about 22 km from Onslow.
Decommissioning plugged 11 onshore production wells, 3 water disposal wells, 1 exploration well and safely dismantled and removed three 150,000-bbl oil storage tanks in addition to production tanks, separator vessels, flowlines, associated process infrastructure, ancillary accommodation, and utilities including the controlled toppling of the 38-m communications tower.
In total, the project resulted in the removal of more than 5,000 tonnes of scrap metal from the island for recycling. Chevron engaged several contractors including Liberty Industrial, AGC, Bhagwan Marine, TAMS Group, Golder Associates, and Astron Environmental Services to assist with the process.
The island is a nature reserve adjacent to a tourism operator, and the rehabilitation process included working with local partners NTC Contracting, Workpower, and the Onslow Indigenous Sea Rangers to plant more than 120,000 native seeds.
Thevenard Island started producing oil in 1989 with about 150 million bbl oil produced over its 25-year life until production ceased in 2014. The area will be returned to the Western Australia government once it is restored to a condition similar and compatible with the adjacent environment.
Decommissioning of the Chevron Australia-operated Barrow Island Joint Venture oil site and associated infrastructure on Barrow Island is expected to start in 2025.
Exploration & Development Quick Takes
OMV Petrom to develop Black Sea gas fields
OMV Petrom will develop Domino and Pelican South gas fields in Neptun Deep offshore block in the Black Sea about 160 km from shore in water depths of 100-1,000 m.
Development includes 10 wells, 3 subsea production systems and associated flow lines, an offshore platform, the main natural gas pipeline to Tuzla, and a natural gas measurement station. The platform generates its own energy, and the entire infrastructure will be operated remotely through a digital twin, OMV said.
OMV Petrom and partner Romgaz will jointly invest up to EUR 4 billion for the development phase, set to bring on stream around 100 billion cu m (bcm) of natural gas. First production is estimated for 2027 and production at the plateau will be about 140,000 boe/d for almost 10 years. Estimated recoverable volumes are about 100 bcm (700 MMboe).
OMV Petrom is operator of Neptun Deep (50%) with SNGN Romgaz SA holding the remaining 50%.
Beach Energy abandons Perth basin gas exploration well
Beach Energy Ltd. found no producible hydrocarbons in the Trigg 1 gas exploration well onshore Perth basin in southwestern Western Australia. The operator will now move the rig to its Trigg Northwest 1 well location.
Trigg 1 reached 4,914 m measured depth on June 3. Gas shows were present in the primary Kingia target however no gas could be recovered with wireline testing. The reservoir is interpreted to be tight with insufficient porosity and permeability to flow gas. Testing this significant southerly step-out of the Kingia play meant that reservoir presence and quality was the primary pre-drill risk for this prospect.
Trigg 1 will be plugged and the pre-planned side-track, Trigg 2, a contingent appraisal well, will not be drilled.
After Trigg Northwest 1, Tarantula Deep 1 and Beharra Spring Deep 2 will be drilled.
Beach is operator of the well in a 50-50 partnership with Mitsui E&P Australia.
Drilling & Production Quick Takes
BW Energy produces from second Hibiscus-Ruche well offshore Gabon
BW Energy Ltd. started production from its second Hibiscus-Ruche Phase 1 development well in the Dussafu license offshore Gabon. Production has been in line with expectations and has stabilized at about 6,000 b/d. DHIBM-4H was drilled as a horizontal well from the BW MaBoMo production jack-up to a total depth of 4,800 m into Gamba sandstone reservoirs on Hibiscus field.
The Borr Norve jackup started drilling Phase 1’s third production well (DHIBM-5H). The campaign targets four Hibiscus Gamba and two Ruche Gamba wells which are expected to add 30,000 b/d of total oil production when all are completed early 2024.
Oil produced at Hibiscus-Ruche is transported by pipeline to the BW Adolo FPSO for processing and storage before offloading to export tankers. BW Energy produced first oil from Hibiscus-Ruche earlier this year (OGJ Online, Apr. 10, 2023).
Separately, commissioning and testing of a second gas lift compressor is ongoing at BW Adolo. The compressor, which will support production from six wells in nearby Tortue field, is expected to begin its final commissioning phase in shortly and, once fully operational, will add another 3,000 b/d.
BW Energy Gabon is operator of the license (73.5%) with partners Panoro Energy (17.5%) and Gabon Oil Co. (9%).
Valeura completes Nong Yao infill drilling
Valeura Energy Inc. has completed its Nong Yao field infill drilling campaign and recent increases in oil production. Valeura drilled two horizontal infill wells on Nong Yao oil field at shallow-water License G11/48 offshore Thailand, in which the company holds a 90% operated working interest.
The wells encountered 1,000 and 700 ft of net oil pay in their horizontal sections, respectively, confirming pre-drill reservoir simulation results. The wells have come onstream as oil producers at a combined initial gross rate of 1,350 b/d.
The Borr Mist KFELS Super B Bigfoot-class jack-up drilling rig is now at Manora oil field where Valeura plans to drill three wells aimed at increasing field production. Upon completion of operations at Manora, anticipated in early August 2023, the rig will move to Wassana field for the company’s five-well infill drilling program.
Saturn returns 90% of production curtailed by Alberta wildfires
Saturn Oil & Gas Inc., Calgary, restored by mid-June over 90% of the estimated 10,000 boe/d (60% oil and NGLs) of production that was curtailed since May 4, 2023, as a result of the wildfires in Alberta.
The company is assessing potential damage of its wells and infrastructure.
Saturn Oil & Gas has operated assets in southeastern Saskatchewan, west central Saskatchewan, and central Alberta.
The company’s Alberta assets—gained through acquisition of Ridgeback Resources Inc.—are comprised of Cardium focused development areas in central Alberta and the Kaybob and Deer Mountain areas of northern Alberta (OGJ Online, Mar. 3, 2023).
Production from the Alberta assets include 8,810 boe/d from the Cardium asset in March, which contributed an average of 3,034 boe/d during first-quarter 2023; and 3,189 boe/d from the north Alberta assets in March, which contributed an average of 1,099 boe/d in the year’s first quarter.
PetroNor restarts infill drilling offshore Congo
PetroNor E&P ASA restarted infill drilling on Tchibeli field, offshore Congo. The program related to the PNGF Sud field complex was paused end-2022 as planned following successful drilling of six wells on Litanzi and Tchibeli NE fields.
The first infill well spudded May 21, 2023, with the jack-up drilling rig Axima. As of June 9, the well has been drilled, logged, and cased at the targeted total depth of 2,694 m MD-2,172 m TVDSS and is about to undergo completion.
Base-case plans are to drill four wells in the field with first oil estimated in August from the initial two wells. Drilling is expected to extend through October.
Year-to-date preliminary allocations indicate that production on PNGF Sud has remained consistently above ~30,000 bo/d gross and ~5,000 bo/d net, supported by the contribution from the six infill wells on Litanzi and Tchibeli NE. This includes steady production from the Vandji exploration discovery in Tchibeli NE.
NEO Energy lets contract to extend Dumbarton field life in UKCS
NEO Energy has let an extension of its integrated services contract to Petrofac for NEO Energy’s Global Producer III floating production storage offtake (FPSO) vessel in the UK Continental Shelf.
Dumbarton field is tied back to the FPSO via subsea manifolds. Petrofac will continue to deliver operations, maintenance, engineering, and construction support to the vessel to extend the field’s life. The extension is worth £250 million.
Current forecasts expect the asset to remain fully operational until at least 2026 when it is due for its next reclassification by DNV. Both NEO Energy and Petrofac will work to extend field life beyond this date.
NEO Energy is 100% owner and operator of Dumbarton field.
PROCESSING Quick Takes
Novatek launches hydrocracking unit at Ust-Luga complex
PAO Novatek has launched its hydrocracking unit at the Ust-Luga complex at the port of Ust-Luga on the Baltic Sea.
The unit was built under an agreement between the company and the Ministry of Energy of the Russian Federation to develop new processing infrastructure.
With the hydrocracker in operation, Novatek will be able to process heavy fractionation residuals (fuel oil) at its gas condensate fractionation infrastructure in Ust-Luga to reach a 99% yield of marketable light petroleum products, the company said in an early June release.
The Ust-Luga complex processes stable gas condensate into light and heavy naphtha, jet fuel, ship fuel component (fuel oil), and gasoil to ship to international markets. The Ust-Luga complex also allows for transshipment of stable gas condensate to export markets.
In 2022, the complex processed 6,943 metric tonnes of stable gas condensate into 6,825 metric tonnes of end products, including 4,208 metric tonnes of light and heavy naphtha, 1,052 metric tonnes of jet fuel, and 1,487 metric tonnes of ship fuel component (fuel oil) and gasoil, and 78,000 tons of LPG.
Strategic Biofuels lets contract for Louisiana renewable fuels plant
Strategic Biofuels LLC has let a contract to SLB to provide carbon sequestration services for subsidiary Louisiana Green Fuels LLC’s (LGF) proposed grassroots renewable fuels plant to be built on a 171-acre tract of land at the port of Columbia, in Caldwell Parish, La., about 25 miles south of Monroe (OGJ Online, Jan. 20, 2022).
As part of the June 27 contract, SLB will provide site derisking and front-end engineering and design (FEED) services for the carbon capture and storage (CCS), or sequestration, complex that will be located on and around the biofuel refinery and adjacent bioenergy with CCS (BECCS) power plant, Strategic Biofuels said.
The agreement additionally covers provisions for future services, including injection operations and long-term carbon dioxide (CO2) monitoring, according to the operator.
Strategic Biofuels also confirmed it has made an application to the US Environmental Protection Agency for a Class VI permit for CCS and has been notified by the agency that the application is administratively complete, with a technical review now under way.
Based on its most recent timeline, Strategic Biofuels said it plans to reach mechanical completion of the LGF and BECCS plants in 2027.
Once operational, LGF’s refinery will be capable of producing nearly 32 million gal/year of renewable fuel with a carbon intensity of -294 from a feedstock of wood waste made up of timber byproducts supplied by responsibly managed, sustainable plantation forests within Louisiana, with the BECCS plant able to generate more than 85 Mw of electric power for a combined offsetting of up to 1.36 million tonnes/year of CO2 emissions, the operator said.
TRANSPORTATION Quick Takes
Tamboran signs Northern Territory LNG offtake MOUs with bp, Shell
Tamboran Resources Ltd. has signed two MOU with bp Singapore Pte. Ltd. and Shell Eastern Trading (Pte.) Ltd. for supply of 4.4 million tonnes/year (tpy) of LNG from Tamboran’s proposed 6.6-million tpy Northern Territory LNG (NTLNG) plant at Middle Arm Development Precinct in Darwin Harbor, Northern Territory, Australia. Shell and bp will purchase 2.2 million tpy each for 20 years.
Tamboran plans to complete NTLNG front-end engineering and design in 2024, targeting formal execution of the sales agreements the following year. Feed gas for the plant has the potential to be supplied from Tamboran’s onshore Beetaloo subbasin natural gas assets, subject to successful Beetaloo appraisal drilling and flow testing in the company’s operated permits, as well as government approvals.
The company earlier this month secured NTLNG’s site (OGJ Online, June 9, 2023).
Tamboran is the largest acreage holder (~1.9 million net prospective acres) and operator in Beetaloo. Its key assets include a 38.75% working interest and operatorship in exploration permits (EP) 98, 117, and 76, a 100% working interest and operatorship in EP 136, EP 143, and EP(A) 197, and a 25% non-operated working interest in EP 161, all in Beetaloo basin.
Tamboran will initially focus on development of the proposed EP 98 Pilot, targeting first production by end-2025, by which point it hopes to have booked a potential 5 tcf of proven-plus-probable (2P) reserves (OGJ Online, Nov. 23, 2022).
Cheniere signs LNG supply agreement supporting Sabine Pass expansion
Cheniere Marketing LLC, a Cheniere Energy Inc. subsidiary, has agreed to a long-term LNG supply agreement with Equinor ASA.
The supply agreement provides for provision of LNG on a free-on-board basis for a purchase price indexed to Henry Hub, plus a fixed liquefaction fee. Delivery of half of the volume will begin in 2027, and delivery of the remaining half, which is subject to, among other things, a positive final investment decision with respect to the first train of the Sabine Pass liquefaction expansion project (SPL expansion project) in Cameron Parish, La., will begin at the end of this decade.
The term of the SPA is 15 years from the start of delivery of the full 1.75 million tonnes/year (tpy) of LNG.
The SPL expansion project is being developed to include up to three natural gas liquefaction trains with an expected total production capacity of about 20 million tpy of LNG. In May 2023, certain subsidiaries of Cheniere Energy Partners LP entered the pre-filing review process with respect to the expansion project with the Federal Energy Regulatory Commission under the National Environmental Policy Act (OGJ Online, Feb. 23, 2023).
With the agreement, total volumes Equinor has contracted with Cheniere is around 3.5 million tpy (OGJ Online, June 9, 2022).
INEOS charters two newbuild LNG carriers for US-Germany shipments
INEOS Energy Trading has chartered two 174,000-cu m newbuild LNG carriers from Mitsui OSK Lines (MOL). The ships will transport LNG to Germany from the US and mark INEOS first foray into the LNG carrier market.
INEOS last year entered a 20-year agreement with Sempra Infrastructure to purchase 1.4 million tonnes/year (tpy) from Sempra’s 13.5-million tpy first phase Port Arthur LNG plant under development in Jefferson County, Tex. (OGJ Online, Dec. 1, 2022). INEOS earlier in 2022 signed a contract for long-term regasification capacity at NV Nederlandse Gasunie subsidiary CS Gas North SA’s planned land-based 8 billion cu m/year German LNG terminal in Brunsbüttel, Germany.
Sempra expects Port Arthur LNG first 6.75-million tpy train to begin commercial operations in 2027, with Train 2 following in 2028 (OGJ Online, Mar. 20, 2023). Construction at Brunsbüttel is expected to be complete in 2026 (OGJ Online, Mar. 6, 2023).
The vessels are being built at Daewoo Shipbuilding & Marine Engineering’s Okpo Shipyard in South Korea. They will join INEOS’ existing fleet of 12 dedicated ethane carriers and be used to service the company’s own demand for natural gas as well as that of select third parties.