GENERAL INTEREST Quick Takes
Jordan Cove LNG project gets Energy Department export approval
US Energy Secretary Dan Brouillette signed the final authorization July 6 for export of LNG from the Jordan Cove project planned for the coast of Oregon.
A gas pipeline and the export terminal received approval from the Federal Energy Regulatory Commission in March (OGJ Online, March 20, 2020).
Pembina Pipeline Corp., Calgary, would build the Pacific Connector pipeline 229 miles from a pipeline hub near Malin, Ore., to Coos Bay, Ore., where a five-train liquefaction facility would be built with a capacity of up to 7.8 million tonne/year. It would be a $10 billion project, according to Pembina, which acquired the project in 2017 and hopes to complete it in 2025.
The Oregon Department of Land Conservation and development in February objected that the Jordan Cove plan is inconsistent with the state’s environmental policies, an objection raised under the Coastal Zone Management Act.
But the commerce secretary has authority to accept or reject the state’s objection, and that decision has not yet been made.
3D Oil completes offshore Otway basin farmout to ConocoPhillips
3D Oil Ltd. has closed its farmout of 80% of Tasmanian offshore Otway basin permit T/49P to ConocoPhillips following approval of documentation by Australia’s National Offshore Petroleum Titles Authority (NOPTA).
ConocoPhillips becomes operator of the permit that stretches down across Bass Strait and along Tasmania’s west coast.
3D will receive $5 million (Aus.) in cash as payment for past expenditure and will be carried through a 3D seismic survey of not less than 1,580 sq km.
Upon completion, processing, and interpretation of the seismic data ConocoPhillips can elect to drill an exploration well to fulfill the current Year 6 work program obligation for the permit. If ConocoPhillips drills the well, 3D will be further carried for up to US$30 million in drilling costs, after which it will contribute 20% in line with the permit interests.
Water depths across the 4,960 sq km permit are around 100m. Two very early wells (Prawn-1 drilled in the northwest of the permit in 1968 and Whelk-1 in the southeast in 1970) were later shown to be invalid targets.
In more recent times the Thylacine and Geographe commercial gas discoveries to the north east of the permit have upgraded the region.
3D Oil was awarded the permit with 100% interest in May 2013. The focus of interest so far has been the Flanagan prospect, a series of tilted fault blocks in the north, and the Seal Rocks prospect, a series of horsetail tilt blocks in the south.
Santos granted production license for Barossa gas project
Santos Ltd., Adelaide, has been granted a production license surrounding its Barossa-Caldita gas fields in the offshore Northern Territory sector of the Bonaparte basin north of Darwin.
The license was granted by the Australian National Offshore Petroleum Titles Administrator (NOPTA) on July 3 following Santos’ application in late March.
The license, NT/L1, replaces the company’s former retention license and contains 10 blocks for a total area of 841 sq km.
The Santos group has yet to sanction the Barossa gas project. The final investment decision was due in June but has been delayed because of market conditions.
Development of Barossa field will involve a floating production, storage, and offloading facility that will separate condensate from gas. Dehydrated gas will then be piped to the onshore Darwin LNG plant where it will be used as backfill for LNG production as the current supply from Bayu-Undan field declines.
Condensate will be exported to market directly from the FPSO.
The pipeline from the field to Darwin was sanctioned by the National Offshore Petroleum Safety and Environment Management Authority in March.
Santos says that Barossa project will produce 3.7 million tonnes of LNG and 1.5 million bbl/year of condensate during an expected 25-year life.
Exploration & Development Quick Takes
Equinor to evaluate North Sea discovery near Kvitebjørn
Equinor Energy AS and partners will consider whether to pursue a gas and condensate discovery near Kvitebjørn field in the North Sea in an overall assessment of the area. Preliminary estimates place the size of the discovery at 3-10 million standard cu m of recoverable oil equivalents (19-63 million boe).
Exploration well 30/2-5 S Atlantis, the first in production license 878, was drilled 17 km south of Kvitebjørn field and 10 km north of Huldra to a vertical depth of 4,359 m subsea and a measured depth of 4,390 m by the West Hercules drilling facility. It was terminated in the Drake formation from the Early Jurassic Age. Water depth at the site is 142 m.
The primary exploration target was to prove hydrocarbons in the Middle Jurassic reservoir of the Brent Group. The well encountered a gas column of about 160 m in the group (Tarbert, Ness, Etive, and Rannoch formations), of which 60 m comprise effective sandstone reservoir: the Ness formation has 30 m of sandstone with poor to moderate reservoir quality, while the Etive formation has 15 m of sandstone, primarily of moderate quality. The Tarbert formation has 10 m of sandstone with poor to moderate reservoir quality, while the Rannoch formation has 5 m of poor quality sandstone.
The well was not formation tested, but extensive amounts of data have been acquired and samples have been taken.
Equinor is operator of the license with 60%. Partners are Source Energy 20%, and Wellesley Petroleum AS 20%.
West Hercules will move on to drill exploration well 35/11-24 S (Swisher prospect) in Equinor-operated production license 248 C in the North Sea.
Neptune finds hydrocarbons near Snorre field
Neptune Energy and partners have discovered hydrocarbons at the Dugong well in PL 882. The well was drilled in 330 m of water 158 km west of Florø, close to existing Snorre field production facilities in the Norwegian North Sea (OGJ Online, June 12, 2020).
The reservoir lies at a depth of 3,250-3,400 m. Logs and cuttings have identified hydrocarbons and a decision has been made to initiate coring. Reservoir operations are ongoing, and results are not yet available. A contingent side-track may be drilled to further define extent of the discovery.
Dugong was drilled by the Deepsea Yantai, a new semisubmersible rig owned by CIMC and operated by Odfjell Drilling.
Neptune is operator at Dugong (40%) with partners Concedo (20%), Petrolia NOCO (20%), and Idemitsu Petroleum Norge (20%).
Vintage Energy wins new permit in Cooper basin
Vintage Energy Ltd. will begin basin modelling, petrophysics and a rock physics trending study leading to acquisition of about 100 sq km of 3D seismic on an exploration permit in the southwest Cooper basin of South Australia immediately south of Warrior oil field.
The company successfully bid for the permit, designated CO2019-E (PELA 679), and holds 100% interest. The company is likely to bring in farminees to help finance the work program, it said.
The fragmented permit, which covers 393 sq km, is held under an initial 5-year term with options for two more 5-year renewals. There is a two-well commitment during the licence term.
Vintage is primarily focused on oil exploration in the region where the permit has oil potential in the Permian of the Cooper basin as well as the Jurassic in the overlying Eromanga basin. The Jurassic reservoirs in Warrior field have produced over 4 million bbl of oil.
The permit has sparse coverage of poor quality 2D seismic, but the company has identified three Jurassic four-way dip closures and one Permian Patchawarra formation stratigraphic play.
The morphology of basement-influenced Jurassic structures located up-dip and along trend of Permian stratigraphic hydrocarbons is analogous to the prolific Western Flank play to the north where Pennington and Bauer oil fields are up-dip of Permian Udacha-Middleton fields’ stratigraphic gas reservoir, the company said.
Drilling & Production Quick Takes
JAPEX starts production from shallow reservoir at Yufutsu field, Hokkaido
Japan Petroleum Exploration Co. Ltd. said heavy crude production started from the shallow reservoir Takinoue formation above the current producing reservoirs of Yufutsu oil and gas field at Tomakomai City, Hokkaido, Japan.
Initial production from the shallow reservoir is about 1,258 b/d. Reservoir evaluation will continue based on production data analysis and further development potential will be examined.
The presence of crude in Takinoue was confirmed by production testing in 2013. Economic viability was secured by workover of existing wells and diversion of idle production facilities, initiating development of the shallow reservoir in June 2017. Production equipment for wellheads and processing facilities for heavy oil were installed, and after production testing and commissioning in June, commercial production began.
ConocoPhillips to restore Alaska, Lower 48 production
ConocoPhillips will begin to restore curtailed Alaska and Lower 48 production in July after cutting back production for second-quarter 2020. Surmont production should increase from curtailed levels in this year’s third quarter.
For second-quarter 2020, curtailments were primarily related to oil production and averaged about 225,000 boe/d on a net basis. Of total net curtailments, about 65% were in the Lower 48, 15% were in Alaska, and 15% were in Surmont in Canada. The remainder were primarily in Malaysia. Including impacts from curtailments and planned seasonal turnaround activity, the company expects production volumes for the second quarter of 960,000-980,000 boe/d. Excluding Libya, and adjusting for closed dispositions and curtailments, second-quarter 2020 production is expected to be in line with the same period a year ago and about 5% below first-quarter 2020.
Second-quarter operational and financial results are expected July 30.
Gazprom begins drilling at Kharasaveyskoye field in Yamal
Drilling of the first producing well at Kharasaveyskoye field on Russia’s Yamal Peninsula began June 12, Gazprom said in a release. Production is expected to begin in 2023.
Well No. 4051 with a projected depth of 2,540 m is the first in gas well cluster No. 5, which will have 11 wells in total. This year, 16 wells are expected to be drilled.
On March 20, 2019, Russian President Vladimir Putin launched full-scale development of Kharasaveyskoye field, which lies mostly onshore, but partly spreads into the Kara Sea. Gas reserves at the field are estimated at 2 trillion cu m.
The estimated volume of gas production from the Cenomanian-Aptian deposits—the first development target—is 32 billion cu m/year. Construction of gas production wells, a comprehensive gas treatment unit, a booster compressor station, and transport and power infrastructure are planned. Horizontal wells for the offshore segment of the field are expected to be drilled from onshore. To transmit gas, a connecting gas pipeline stretching 106 km to Bovanenkovskoye field will be built. The gas will then be fed into Russia’s Unified Gas Supply System.
The company later plans to develop the deeper-lying Neocomian-Jurassic deposits.
PROCESSING Quick Takes
Chinese operator starts up world’s largest single-train methanol plant
Ningxia Baofeng Energy Group Co. Ltd. (Baofeng Energy) has commissioned the world’s largest single-train methanol plant as part of its new 600,000-tonnes/year coal-to-olefins (CTO) complex at Ningdong Energy Chemical Base in Yinchuan City, Ningxia Province, China.
Designed by and equipped with proprietary DAVY process technology and catalysts from Johnson Matthey, the plant uses a feedstock of coal-derived synthesis gas (syngas) to produce 2.2 million tpy of stabilized methanol, which Baofeng Energy uses for production of olefins in a downstream unit, Johnson Matthey said.
Startup of the plant follows the operator’s 2017 award to Johnson Matthey, the scope of which included delivery of licensing for the methanol synthesis plant flowsheet, associated engineering, technical review, commissioning assistance, and catalyst supply.
Johnson Matthey previously provided licensing and design for a previous unit Baofeng Energy commissioned in 2014, the service provider said.
With the new methanol plant now operating at full rates, Baofeng Energy’s Ningdong chemical complex is now capable of producing 4 million tpy of methanol, 1.2 million tpy of olefins, 4 million tpy of coke, and 780,000 tpy of specialty chemicals from coal-derived feedstock.
With instrumentation installation assistance from Shanghai Chenzhu Instrument Co. Ltd. (Chenzhu) Baofeng Energy first started up its new plant’s methanol synthesis tower—which was designed by China Chengda Engineering Co. Ltd. (Chengda) using Johnson Matthey’s DAVY technology and manufactured by Dongfang Boiler Co. Ltd.—and associated 105,000-cu m/hr air separation unit on May 29, 2020, according to separate releases from Chenzhu and Chengda.
Baofeng Energy—which scaled back methanol production capacity to 2.2 million tpy from an originally planned 2.6 million tpy in 2018—invested 15.28 billion yuan to complete both the new methanol plant and CTO complex, the latter of which first entered production in October 2019, according to a Nov. 15, 2018, release from Baofeng Energy and reports from Chinese local media.
In late 2019, Baofeng Energy announced the release of an environmental impact assessment for a project that would involve construction of a newly proposed 500,000-tpy CTO complex at Ningdong, which would also include a new 1.5-million tpy methanol plant, according to a Dec. 3, 2019, release from the operator.
Rosneft’s Syzran refinery sells first batch IMO 2020-compliant fuel
Rosneft PJSC subsidiary JSC Syzran Refinery has sold and loaded the first batch of low-sulfur fuel oil (LSFO) that complies with the International Marine Organization’s (IMO) new regulations requiring ships to use marine fuels with a sulfur content below 0.5% from its 8.5 million-tonnes/year Syzran refinery in Russia’s Samara region.
The refinery’s first 700-tonne batch of residual marine low-sulfur (RMLS-40) E II was delivered for loading to the port of Novorossiysk in the Black Sea on June 16, Rosneft said.
The company did not disclose the buyer.
With a sulfur content of no more than 0.5%, the RMLS 40 E II forms one part of Rosneft’s new product line that complies with IMO’s Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL Convention), which lowered the maximum sulfur content of marine fuel oil used in ocean-going vessels from 3.5% to 0.5% beginning Jan. 1, 2020. The operator also offers RMLS 40 E I, which features a sulfur content of no more than 0.1%.
This initial sale of RMLS 40 E II follows the Syzran refinery’s start of production of the IMO-compliant marine fuel in May, according to a May 21, 2020, release from the operator.
Alongside the Syzran refinery, Rosneft said it also currently produces the RMLS 40 product line at its Russian refining subsidiaries’ following operations:
- LLC RN-Komsomolsk Refinery’s 8.3 million-tpy refinery in Komsomolsk-on-Amur, Khabarovsk Territory.
- JSC Achinsk Refinery VNK’s 7.5 million-tpy refinery in Bolsheuluisky District, Krasnoyarsk Territory.
- JSC Angarsk Petrochemical Co.’s 10.2 million-tpy refinery in Angarsk, Irkutsk Region.
- JSC Ryazan Oil Refining Co.’s 17.1 million-tpy refinery in Russia’s Central Federal District, about 120 miles southeast of Moscow.
- PJSC ANK Bashneft’s 23.5 million-tpy integrated refining complex in Ufa, which includes Bashneft-Ufaneftekhim’s 9.5 million-tpy refinery, Bashneft-Novoil’s 7.4 million-tpy refinery, and Bashneft-UNPZ’s 6.6 million-tpy refinery.
In first-quarter 2020, Rosneft said its refining subsidiaries supplied 112,000 tonnes of RMLS 40 E II fuel to both domestic and foreign shipowners.
Meridian cleared to proceed with Davis refinery
The North Dakota Supreme Court has upheld a lower court decision affirming the North Dakota Department of Environmental Quality’s (DEW) June 2018 issuance of Meridian Energy Group Inc.’s air quality permit to construct (PTC) its long-planned grassroots 49,500-b/sd high-conversion Davis refinery in Belfield, Billings County, ND.
The decision marks the end of the litigation process related to the Davis PTC, granting full approval for the project to proceed as planned, Meridian said on June 30.
Meridian’s Davis PTC marks the first permit approved for construction of a full-conversion refinery of its size and complexity under classification as a synthetic minor source (SMS) of air contaminants on DEQ’s findings that emissions from the proposed plant would be substantially below stringent federal standards, and would be monitored to such an extent that the refinery qualified as an SMS.
“The Davis design that is the basis for the PTC will result in Davis having total emissions of one-eighth of industry average, and less than one-half of the industry’s GHG emissions. If one half of the refining industry in the [US] were converted or replaced with Meridian technology, the industry would show a reduction of 88 million tons of GHG per year,” said William Prentice, Meridian’s chief executive officer and chairman.
With front-end engineering design currently nearing completion by contractor McDermott International and site-preparation activities under way, the refinery—which will be equipped with technology from Axens Group—is scheduled to enter commercial operation during fourth-quarter 2023 at a currently estimated overall cost of about $1 billion.
TRANSPORTATION Quick Takes
Alaska LNG cost-estimate cut by $5.5 billion
Alaska Gasline Development Corp. (AGDC) has revised the Alaska LNG project’s estimated cost downward by $5.5 billion, to $38.7 billion.
The project involves building a three-train, 20-million tonne/year liquefaction plant at Nikiski, Alas., on the Kenai Peninsula coast of southern Alaska, and an 800-mile, 42-in. OD pipeline to Nikiski from the North Slope, where it would draw gas especially from Point Thomson and Prudhoe Bay fields’ estimated 31-tcf reserves. A gas treatment plant would also be built on the North Slope.
AGDC described the cost reductions as capitalizing on “technology and process improvements developed in the LNG industry over the past several years, reflecting maturation of the LNG industry.” These improvements include advancements in gas liquefaction technology and modular construction techniques, lower engineering costs, and a streamlined project management team, the State of Alaska public corporation said.
AGDC has obtained US Federal Energy Regulatory Commission authorization to construct and operate Alaska LNG.
Harvest completes Ingleside pipeline construction
Harvest Midstream Co. has completed its new Ingleside pipeline, which by end-2020 will move up to 600,000 b/d of crude oil from Harvest’s Midway terminal in Taft, Tex., to all three export terminals in Ingleside, Tex. The pipeline can currently deliver to Flint Hills Resources Ingleside Terminal and will be able to ship barrels to Buckeye Partners’ South Texas Gateway terminal in July 2020 and Moda Midstream LLC’s Ingleside Energy Center in September 2020.
The 24-mile, 24-in. OD pipeline will ship as much as 380,000 b/d supplied by existing Harvest Eagle Ford pipeline systems.
Harvest expects to complete Phase 1 construction at its 160-acre Midway terminal site by third-quarter 2020. Phase 1 includes pumps to achieve the 600,000-b/d planned pipeline capacity. Harvest plans to build as much as 10 million bbl of storage at the site.
Construction of the pipeline and terminal began late-2019.
EPP ethylene export terminal exceeds expected loading capacity
Enterprise Products Partners (EPP) LP’s marine export terminal at Morgan’s Point, Tex., has exceeded design interim loading capacity and the company plans to export more 175 million lb in the month of June. The company expects the terminal, a 50-50 joint venture with Navigator Holdings Ltd., to reach its full 2.2 million lb/hr loading rate in fourth-quarter 2020.
EPP also expects by end-2020 to complete construction of a 66-million lb aboveground ethylene storage tank which will allow the Houston Ship Channel terminal’s annual capacity to reach its designed 2.2 billion lb. Enterprise’s high-capacity open access 600-million/lb underground ethylene storage hub in Mont Belvieu, Tex., connects to the export terminal via a 16-mile pipeline.
Four other ethylene pipeline systems connect to EPP’s. Enterprise expects to complete three additional connections by end-2020, linking its system to most ethylene production capacity in Texas.
The terminal exported its first cargo in January 2020. It is now loading what EPP describes as a record-sized ethylene cargo of 44 million lb on the Navigator Eclipse.
