GENERAL INTEREST Quick Takes
Mountain Valley pipeline clears regulatory hurdle
The US Fourth Circuit Court of Appeals has ruled that construction of EQM Midstream Partners LP’s 303-mile, 2-bcfd Mountain Valley natural gas pipeline would not jeopardize endangered species along its route. The Sierra Club and other environmental groups had sought to stay a biological opinion issued in September by the US Fish and Wildlife Service in order to protect two species of fish and two species of bats.
Water-crossing work on the pipeline through a 25-mile area including two watersheds and about 1,000 bodies of water, however, remains stalled pending a decision by the Fourth Circuit on whether to overturn the project’s US Army Corps of Engineers’ water permits (OGJ Online, Nov. 12, 2020).
Mountain Valley would connect Appalachian basin natural gas production to mid-Atlantic markets. EQM expects to complete the project in 2021.
EQM Midstream owns a 45.5% operating interest in MVP LLC, with affiliates of NextEra Energy Inc., Consolidated Edison Inc., AltaGas Ltd., and RGC Resources Inc. owning the balance.
Norway offers 136 offshore tracts, will award licenses in first quarter
Norway has launched its 25th licensing round encompassing 136 blocks in the Norwegian Sea and the Barents Sea.
Applications for the round are due Feb. 23, 2021. Awards are expected during first-quarter 2021.
The Ministry of Petroleum and Energy said a recent resource report showed substantial undiscovered resources remain in all areas on the Norwegian Continental Shelf and that companies will have access to acreage that has not yet been available in annual APA rounds.
“The announced acreage features a broad range of exciting plays that, so far, have not been extensively explored,” said Torgeir Stordal, the agency’s director of exploration.
An invitation to apply for petroleum production licenses, an updated map of the announced blocks, regulatory requirements and more information was posted on the Norwegian Petroleum Directorate website.
Triangle farms into permit adjacent Cliff Head field
Triangle Energy Ltd. has taken a 78.75% interest and operatorship of offshore North Perth basin exploration permit WA-481-P adjacent to the company’s Cliff Head oil field following a farm-in deal with Pilot Energy Ltd., Sydney.
Pilot currently holds a 60% interest but is on the cusp of acquiring the remaining 40% from Key Petroleum Ltd. Completion of that acquisition will trigger the farm-out deal with Triangle.
In a complementary deal, Pilot will take a 21.25% interest in the Cliff Head production license WA-31-L by acquiring all the interests of Royal Energy Ltd. Triangle has the remaining 78.75% of Cliff Head along with operatorship.
Under the terms of the WA-481-P acquisition agreement Triangle will pay Pilot $300,000 (Aus). in cash and free carry Pilot for 100% of the completion of its share of the proposed Year 3 $5.5 (Aus.)-million minimum work program for the permit.
This includes 2000 km of 2D seismic reprocessing, 350 sq km of new 3D seismic acquisition, along with geological and geophysical studies. A number of prospects and leads exist in the permit within close proximity to Cliff Head production infrastructure.
Triangle has agreed that Pilot’s share of any oil and gas discoveries in WA-481-P will be developed and produced through Cliff Head facilities on the same basis as Triangle’s share.
Cliff Head facilities include the offshore platform and pipeline to the shore-based Arrowsmith separation and treatment plant.
As an adjunct to formation of the Triangle-Pilot JV, the two companies also have agreed to form a wind and solar project joint venture to assess feasibility of such development projects centered around Cliff Head oil field production facilities.
Exploration & Development Quick Takes
Elixir finds gassy coals in new Mongolian subbasin
Elixir Energy Ltd., Adelaide, as part of its coal seam gas exploration program in southern Mongolia, has discovered gassy coals in a new subbasin within its Nomgon IX production sharing contract area.
This year, the company has drilled seven wells that intersected significant coal seams over a total west to east distance of 43 km.
Most recently, the Yangir 1S stratigraphic hole, in the Yangir subbasin 24 km west northwest of the original Nomgon-1 discovery well in the Nomgon subbasin, intersected 27 m of gassy coals. Now at 347 m, drilling continues.
Elixir reported active gas bubbling from the Yangir 1S coals recovered to surface as well as in the mud pit—an unusual occurrence and considered highly promising in coals encountered at a relatively shallow depth of 260 m.
The company plans a follow-up appraisal program in 2021 expected to begin with a fully desorbed and tested core hole.
In addition, the Hutul 1S stratigraphic hole, some 19 km east of Nomgon-1, was recently drilled to evaluate the eastern most sector of the Nomgon subbasin. It reached 560 m TD and intersected 6 m of coal. Further work is needed, but Elixir says the result is encouraging.
The final stratigraphic hole in the 2020 program is likely to be delayed because of new COVID-19 prevention measures in the country following instances of community transmission for the first time.
The Nomgon PSC is just north of the Mongolian border with China.
APT to begin seismic work in Ruvuma PSA, Tanzania
ARA Petroleum Tanzania Ltd. (APT) and joint partners in the Ruvuma PSA will begin a seismic and drilling program to develop the Ntorya gas discovery within the license.
Ruvuma PSA consists of two blocks, Mtwara and Lindi, and is spread over an area of 6,079 sq km. About 80% of the area is onshore, while the remaining 20% is offshore.
The JV has agreed to a work program and budget to acquire a 400 sq km full fold (454 sq km surface footprint) 3D survey in second and third quarter of 2021 to align with the next available operational weather window in Tanzania.
Currently, the seismic database contains 2D lines of varying vintages and quality. Modern 3D—to be acquired through vibroseis and explosive sources to take account of surface topography and minimize impact on the local community—is expected to improve subsurface imaging ahead of full field development.
APT will start contracting and procurement of services for Chikumbi-1 well (CH-1) and will secure long lead items (LLIs) including the well head and rig. The JV will look at early rig mobilization to Tanzania to mitigate against a key uncertainty on the timeline to spud.
Drilling preparation activity will begin in early 2021, including civil works for the well pad in preparation for rig arrival, securing LLIs, and deployment of services to Tanzania in anticipation of spud, currently scheduled for January 2022.
The JV now intends to submit a revised gross budget of $22.8 million to Tanzanian authorities.
Total contracts deepwater rigs for Suriname Block 58
Total E&P Suriname submitted a conditional letter of award to Maersk Drilling for use of Maersk Developer and Maersk Valiant deepwater rigs for an exploration and appraisal project in Block 58 offshore Suriname. The campaign is expected to commence in early 2021, with estimated combined duration of 500 days.
Maersk Developer is column-stabilized dynamically positioned semisubmersible rig able to operate in water depths up to 10,000 ft. It was delivered in 2009 and is currently operating offshore Suriname.
Maersk Valiant is a high-specification 7th generation drillship with integrated MPD capability which was delivered in 2013. It is currently warm-stacked in Aruba after finishing a campaign in Mexico earlier this year.
The contract is valued by the service provider at $100 million, including rig upgrades and integrated services provided.
Total and Apache Corp. in December 2019 formed a joint venture to explore the block (OGJ Online, Dec. 23, 2019). Apache served as operator for the first three exploration wells before transferring operatorship to Total (OGJ Online, July 29, 2020).
Drilling & Production Quick Takes
Johan Sverdrup partners to increase capacity
Equinor and its Johan Sverdrup partners have agreed to further production capacity increases from the North Sea field.
They now expect Johan Sverdrup to deliver around 500,000 b/d of oil by yearend, nearly 60,000 b/d more than under the base production when the field came on stream just over 1 year ago (OGJ Online, Oct. 7. 2019).
Plant capacity was tested in November to verify a possible production rise from the current 470,000 b/d of oil (OGJ Online, Mar. 30, 2020).
The field is using water injection to secure high recovery of reserves and maintain production at a high level, Equinor said. Phase 2 field development is on schedule to produce in fourth-quarter 2022. Full-field plateau production capacity is expected to rise to 720,000 b/d from 690,000 b/d.
Johan Sverdrup is the third largest oil field on the Norwegian continental shelf, with expected recoverable reserves of 2.7 billion boe. It is powered from shore with low CO2 emissions per bbl. Emissions during the field life are estimated at less than 0.7kg CO2 per produced bbl.
Equinor is operator (42.6%) with partners Lundin Energy Norway (20%), Petoro (17.36%), Aker BP (11.57%), and Total (8.44%).
Lundin drills dry well east of Johan Castberg
Lundin Energy Norway AS will plug Barents Sea well 7221/4-1. The well, drilled in production license 609 as a shared well between Lundin-operated production licenses 609 and 1027, is dry.
The well—the 11th in the license—was drilled to a vertical depth of 1,537 m subsea by the West Bollsta drilling rig about 30 km east of Johan Castberg field, about 12 km east of the 7220/6-2 R (Neiden) oil and gas discovery, and 230 km northwest of Hammerfest. It was terminated in carbonate-bearing rocks from the Late Permian age (Røye formation). Water depth at the site is 370 m.
The primary and secondary exploration targets for the well were to prove petroleum in reservoir rocks in the Kobbe formation from the Middle Triassic age and the Havert formation from the Early Triassic age.
In the primary target, the well encountered a 6-m sandstone layer with poor reservoir quality. There were traces of petroleum. No reservoir rocks were encountered in the secondary target. Extensive data acquisition was carried out.
The drilling rig will now drill well 7219/11-1 in production license 533 B, where Lundin Energy Norway AS is operator.
ONGC continues CPO-5 block testing onshore Colombia
ONGC Videsh and partners tested the Indico 2 appraisal well in CPO-5 block in the Llanos basin onshore Colombia and plan additional drilling in 2021, partner GeoPark Ltd. said Nov. 12.
The well was drilled and completed to a total depth of 10,925 ft about 0.8 km northwest and 151 ft downdip of the Indico 1X well, with a net pay of about 161 ft. A test conducted through natural flow in the Une (LS3) sandstone formation resulted in a production rate of 5,500 b/d of oil of 35.2° API, with 0.1% water cut, through a 40/64-in. choke and wellhead pressure of 330 psi.
Additional production history is required to determine stabilized flow rates of the well. Surface testing facilities are in place and the well is already in production.
The drilling rig moved to the Aguila exploration prospect 4.9 km southeast of Indico field, which was expected to spud in late November. Aguila is a multi-target prospect with the Lower Sands (LS3) unit of the Cretaceous Une formation as the main objective (an analogue of existing and producing Mariposa and Indico fields), while also looking for hydrocarbon potential in Guadalupe and Gacheta formations.
Further exploration, appraisal, and development activities are budgeted to continue in the CPO-5 block in 2021 (mostly in the year’s first half) with drilling of 5-6 gross wells plus the acquisition of 336 sq km of 3D seismic.
ONGC Videsh is operator (40%) in CPO-5 with partners GeoPark (30%) and Petrodorado Energy (30%).
PROCESSING Quick Takes
Phillips 66 expands Sweeny fractionation capacity
Phillips 66 has started up two new NGL fractionators at its Sweeny Hub in Old Ocean, Tex., quadrupling the site’s processing capacity to 400,000 b/d (OGJ Online, June 27, 2018).
Now in operation, the two 150,000-b/d fractionators reached mechanical completion this summer and came online in September-October, on time and despite challenges posed by weather events and the ongoing COVID-19 pandemic, said Phillips 66 and S&B Engineers and Constructors Ltd., which delivered engineering, procurement, and construction on the units based on its own proprietary fractionation plant design.
Part of the $1.4-billion Sweeny Hub Phase 2 expansion and completed about $100 million under budget, the fractionators—two of the world’s largest—form part of the new fractionation complex at Phillips 66’s 256,000-b/d Sweeny refinery, the heart of the Sweeny Hub, which also includes the operator’s Freeport LPG export terminal and nearby Clemens Caverns storage facility, the latter of which recently increased capacity to 16.5 million bbl to support the new fractionators, according to Phillips 66.
Alongside establishing Sweeny as the third-largest NGL fractionation hub in the US, the new fractionators boost integration between Phillips 66 and joint ventures DCP Midstream LLC and Chevron Phillips Chemical Co. LLC (CPChem), with the DCP-Phillips 66 Partners’ Sand Hills pipeline to be among the pipelines delivering raw-NGL feed, also known as Y-grade, for processing. CPChem, which operates steam crackers at Sweeny and Baytown, Tex., will be among customers taking ethane from Sweeny for conversion into chemicals and plastics.
Additionally, Phillips 66 said it will market the propane, butanes, and pentanes-plus domestically and abroad, the latter through the Freeport terminal. Phillips 66 Partners also built a pipeline to transport pentanes-plus to the Pasadena terminal near Houston and is constructing another to transport ethane from Clemens Caverns to petrochemical plants in South Texas.
Underpinned by long-term customer commitments, the two new fractionators follow startup of the first 100,000-b/d Sweeny fractionator in late 2015 (OGJ Online, Dec. 8, 2015).
Chinese operator lets contract for PDH units
Kingfa Sci. & Tech. Co. Ltd. subsidiary Ningbo Kingfa Advanced Materials Co. Ltd. has let a contract to Lummus Technology LLC to license technology for two new propane dehydrogenation (PDH) units to be built at its complex in the Qingzhi Industrial Park of Ningbo Economic and Technological Development Zone, Ningbo City, Zhejiang Province, adjacent to China’s second largest port of Beilun.
As part of the contract, Lummus—alongside catalyst partner Clariant International Ltd.—will license its proprietary CATOFIN PDH technology process as well as provide the basic engineering package, technical services, and catalyst supply for the two PDH units, each of which will have a production capacity of 600,000 tonnes/year to boost the site’s propylene production capacity by 1.2 million tpy, the service provider said.
While it disclosed neither a value nor timeframe for its work under the agreement, the service provider confirmed this latest contract follows Ningbo Kingfa’s previous award to Lummus for licensing of CATOFIN PDH technology for the Ningbo plant’s first PDH unit.
The new PDH units come as part of the operator’s Phase 2 and Phase 3 expansion projects at the complex, according to Mark Yang, Ningbo Kingfa’s general manager.
Established in 2011, Ningbo Kingfa’s 16-billion yuan complex, in addition to propylene, produces isooctane, methyl ethyl ketone, 2-butanone, isooctane, n-butane, sulfuric acid, LPG, hydrogen, and mixed pentanes, according to the company’s website.
Last year, Ningbo Kingfa and Zhejiang Energy Group Co. Ltd. signed a cooperative framework agreement under which Ningbo Kingfa would provide hydrogen from its Ningbo complex to a proposed station to be built by Zhejiang Energy, according to an Aug. 21, 2019, release from Ningbo Kingfa. Further details regarding the proposed strategic partnership have yet to be revealed.
ANOPC advances grassroots hydrocracking complex
TechnipFMC PLC has completed all necessary conditions to begin engineering, procurement, and construction (EPC) activities under its previously awarded contract by Assiut National Oil Processing Co. (ANOPC)—established in 2018 by Egyptian General Petroleum Corp. subsidiary Assiut Oil Refining Co. (ASORC)—for new units to be installed at ANOPC’s proposed 2.5-million tonnes/year (tpy) grassroots hydrocracking complex in Assiut, Egypt.
As of Nov. 30, TechnipFMC said it has now started delivery of EPC services on the following major units for the proposed Assiut hydrocracking complex (AHC): Vacuum distillation unit, diesel hydrocracking unit, delayed coking unit, distillate hydrotreating unit, and hydrogen production unit.
The service provider’s scope of work under the contract also covers EPC on other unidentified process units, interconnections, off sites, and utilities.
ANOPC’s AHC, once in operation, will process 2.5 million tpy of heavy fuel oil (mazut) from ASORC’s nearby 4.5-million tpy Assiut refinery—about 400 km south of Cairo—to produce about 2.8 million tpy of Euro 5-quality diesel and other high-value products.
With site preparation works in Assiut for construction of the complex started in 2019, the AHC currently remains scheduled for startup in 2022.
TRANSPORTATION Quick Takes
Enbridge gets Line 3 construction go-ahead
Enbridge Inc.’s Line 3 replacement project has received approval from the Minnesota Public Utilities Commission (MPUC) to begin construction. The company also was granted its Clean Water Act (CWA) Section 404 permit from the US Army Corps of Engineers. The one outstanding permit for the project, according to Enbridge, is a storm water permit provided by the Minnesota Pollution Control Agency (MPCA).
MPCA in November issued the project’s CWA Section 401 water quality certification as well as a wastewater permit and approval for an air emissions cap (OGJ Online, Nov. 13, 2020).
The Line 3 replacement would add 370,000 b/d of capacity to the line, currently limited to 390,000 b/d. That would return it to the 760,000 b/d level it had reached before voluntary restrictions on its pressure reduced flows.
Enbridge hopes to replace all of Line 3’s 1,031 miles from Hardisty, Alta., to Superior, Wisc. The company has already replaced several segments, including some in Canada, most of the 13 miles in North Dakota and all of the 14 miles in Wisconsin. The replacement segment in Minnesota would be 337 miles, including eight pump stations.
Venture Global awards Plaquemines LNG EPC to KBR
Venture Global LNG Inc. awarded KBR the engineering, procurement, and construction (EPC) contract for the 10-million tonne/year (tpy) Phase 1 of Venture Global’s Plaquemines LNG liquefaction plant, under development in Plaquemines Parish, La. KBR will integrate Baker Hughes-produced 0.6-million tpy modular trains at Plaquemines LNG, the same systems being delivered and installed at Venture Global’s 10-million tpy Calcasieu Pass LNG project, in Cameron Parish, La. Kiewit Louisiana Co. is the EPC contractor for Calcasieu Pass LNG.
Each plant will use 18 of the Baker Hughes trains. The first 18 will be installed at Calcasieu Pass LNG, the next 18 at Plaquemines LNG. Venture Global expects production to begin at Calcasieu Pass in 2022 and at Plaquemines in 2024.
The company took delivery of the first two trains for the Calcasieu Pass plant in November (OGJ Online, Nov. 11, 2020). Kiewit Louisiana Co. is the EPC contractor for Calcasieu Pass LNG.
Plaquemines LNG has received all required regulatory approvals and signed binding 20-year offtake agreements with Polish-state PGNiG SA (2.5 million tpy) and Électricité de France SA (1 million tpy). Venture Global plans to develop a second 10-million tpy phase of the project using the same technology.
AIE moves Port Kembla forward with site lease
Squadron Energy Group unit Australian Industrial Energy Pty Ltd. (AIE) has signed a long-term lease agreement with NSW Ports for a dockside site in Port Kembla, 112 km south of Sydney in New South Wales, for development of the company’s proposed $250 million (Aus.) LNG import terminal (OGJ Online, Apr. 1, 2020).
The lease agreement includes a 10-year initial term with options to extend up to a maximum of 25 years.
AIE will immediately begin a site handover process, paving the way for the commencement of construction work.
The company says construction is expected to take 18-20 months with the terminal expected to receive first LNG by end 2022.
In October, Squadron bought out its Japanese partners in AIE (JERA and Marubeni Corp.) to move to a 100% interest in the venture (OGJ Online, Oct. 20, 2020).
The terminal will provide capacity to meet 70-75% of New South Wales’ gas demand with a supply of 100 petajoules/year.
The project will import LNG by seaborne carriers and transfer it to a permanently moored floating storage and regasification unit in the harbor. Construction work includes associated wharf facilities and a 6 km-long pipeline connection to the existing Australian east coast pipeline grid.
