GENERAL INTEREST Quick Takes
BP to sell interest in Oman Block 61
BP PLC agreed to sell a 20% participating interest in central Oman Block 61 to Thailand’s PTT Exploration and Production Public Co. Ltd. (PTTEP) for $2.6 billion.
The 3,950-sq km block, containing the largest tight gas development in the Middle East, has had two phases of development; Khazzan, which began production in 2017, and Ghazeer, in October 2020 (OGJ Online, Sept. 25, 2017; Oct. 12, 2020).
The developments, targeting 10.5 tcf of gas resources, have combined daily production capacity of 1.5 bcf of gas and more than 65,000 bbl of condensate. Gas from Block 61 is exported for domestic consumption into Oman’s national gas grid, while also boosting availability of feedstock supply for Oman LNG.
Subject to approval from the Sultanate of Oman and partners, the deal is expected to close this year. The agreed total consideration comprises $2.45 billion payable on completion and $140 million payable contingent on pre-agreed future conditions.
BP will remain operator with 40% interest with partners OQ (30%), PTTEP (20%), and Petronas (10%).
Energean makes Karish North FID
Energean PLC has taken final investment decision (FID) on the Karish North gas development, offshore Israel, 21-months after the discovery announcement, and plans to increase the liquid processing capacity of the Energean Power FPSO.
The Karish North discovery will be commercialized via tie-back to the Energean Power FPSO, which will sit 5.4 km away (OGJ Online, Apr. 16, 2019; Apr. 9, 2020). First well production, expected in second-half 2023, is expected to be up to 300 MMscfd (3 billion cu m/year). The company expects initial capital expenditure to be $150 million.
To accelerate development, Energean signed an 18-month, $700 million term loan facility agreement with JP Morgan AG and Morgan Stanley Senior Funding Inc.
Following first gas from Karish North, the overall Karish project well stock will be able to produce more than the full 8 billion cu m/year capacity of the FPSO, the company said Jan. 14.
The loan also will fund the $175-million up-front consideration for the acquisition of the minority interest in Energean Israel Ltd., which becomes payable on transaction close, expected in this year’s first quarter (OGJ Online, Dec. 30, 2020).
The loan will also be used to fund some $100 million of capital expenditure required to install the second oil train and second riser on the Energean Power FPSO, which will increase liquids production capacity to 40,000 b/d of oil from 21,000 b/d and allow maximum gas production of 800 MMscfd (8 billion cu m/year, from 6.5 billion cu m/year). Both the oil train and the second riser are expected to become operational during 2022.
The early 2022 offshore Israel exploration and appraisal drilling program will also be funded with the loan. Plans are to drill five wells including appraisal of the potential oil rim that was identified as part of the Karish development drilling campaign plus exploration of further prospective gas and liquids volumes within the Karish lease.
In Block 12, which lies the Karish and Tanin leases and is estimated to contain gross prospective recoverable resources in excess of 108 billion cu m (3.8 tcf), the company expects a first well to target the 20-bcm Athena prospect. Success at Athena would derisk the remaining 88 bcm of prospective resources in the block, and any discovery in the block would be prioritized over development of Tanin.
Turkmenistan, Azerbaijan sign MoU for Caspian Sea field
Turkmenistan and Azerbaijan have signed a memorandum of understanding on joint exploration and development of Dostluk field in the Caspian Sea, the Turkish Foreign Ministry reported Jan. 21.
While no specific details were given, TIbrahim Ahmadov, deputy head of the public relations and events at State Oil Co. of Azerbaijan Republic (SOCAR), told Trend News Agency that reserves of the oil and gas field “can be approved by carrying out modern methods of seismic exploration and probably, exploratory drilling,” and that “technical and commercial issues related to the future development” of the field will need to be outlined.
During the Soviet period, Ahmadov told Trend, exploratory works showed reserves similar to Karabagh field. In March 2020, SOCAR and Equinor confirmed a discovery at Karabagh, 120 km offshore Baku in the Azerbaijan sector of the Caspian Sea (OGJ Online, Mar. 24, 2020). At the time, SOCAR’s president, Rovnag Abdullayev, said the estimated size of discovered volumes at Karabagh—some 60 million tons—is enough to pursue commercial development.
Following the collapse of the Soviet Union, ownership of the field was disputed. In 2018, the Convention on the Legal Status of the Caspian Sea was signed by Turkmenistan, Kazakhstan, Russia, Azerbaijan, and Iran, marking the beginning of efforts to clarify oil and gas rights and accommodate development of a long-discussed pipeline to carry gas from Turkmenistan to Europe via Azerbaijan and Turkey (OGJ Online, Aug. 6, 2018).
Exploration & Development Quick Takes
Petrobras, ExxonMobil identify hydrocarbons offshore Brazil
Petróleo Brasileiro SA (Petrobras) will analyze well data to assess the potential of a hydrocarbon discovery at a Block C-M-411 well in the Campos basin presalt. The data will also be used to direct exploratory activities in the area.
Well 1-BRSA-1377-RJS (Urissanê) lies some 200 km from the coast of Rio de Janeiro in water depth of 2,950 m.
Petrobras is operator of the block under a 50-50 partnership with ExxonMobil Exploração Brasil Ltda. (50%) (OGJ Online, Sept. 28, 2017).
ExxonMobil readying West Barracouta final infrastructure
ExxonMobil subsidiary Esso Australia Pty Ltd. is nearing completion of its West Barracouta gas project in Bass Strait. The unit is readying construction of the project’s final subsea infrastructure.
The arrival of the Subsea 7 Seven Eagle Diving Support Vessel in Victoria means the company is on-track to have West Barracouta gas flowing to the Australian domestic gas market this year.
The development, in license VIC/L1 in the offshore Gippsland basin of Victoria, will be tied back to the existing Barracouta production infrastructure (OGJ Online, Dec. 13, 2018).
“The Esso-BHP Gippsland Joint Venture has been the largest supplier of gas to the eastern Australia market for more than 50 years. In fact, Barracouta is the first offshore field ever discovered in Australia,” said Nathan Fay, chairman, Esso Australia.
Over that time, the company’s operations have delivered more than 4 billion bbl of oil and 10 tcf of natural gas to Australia, more than half of all the oil ever produced in Australia, and enough gas to power almost every home in Australia for a decade, he said.
Esso Australia Pty Ltd. operates the Gippsland basin 50-50 joint venture with BHP Billiton Petroleum (Bass Strait) Pty Ltd.
OGDCL discovers gas, condensate at Sial-1 well
Oil and Gas Development Co. Ltd. (OGDCL) and Government Holdings Pvt. Ltd. discovered gas and condensate from the Sial-1 exploratory well in Pakistan’s Hyderabad district in Sindh Province.
The well was drilled to 2,442 m. The structure of Sial-1 was tested from the Lower Goru formation at 1.146 MMcfd gas and 680 b/d condensate at 460 psi wellhead flowing pressure through a 32/64-in. choke.
OGDCL is operator with 95%. Government Holdings holds the remaining 5%.
Advent signs agreement for well offshore New South Wales
Advent Energy Ltd., Perth, has signed a preliminary well services agreement with drilling and engineering consultancy Add Energy (AE) for work in exploration permit PEP 11 in the Sydney basin offshore New South Wales.
AE will review rig availability and engagement terms for a drilling program in the Baleen prospect off the coast between Sydney and Newcastle.
The agreement also calls for AE to look into the regulatory and environmental requirements as well as establish a drilling campaign schedule that includes a review of a program for geosequestration drilling which is part of the Baleen project.
Advent has submitted a drilling application to Australia’s National Offshore Petroleum Titles Administrator (NOPTA) for the Baleen-1 wildcat and the application is in its final decision phase.
The prospect is in the northern sector of the 4,576-sq km permit about 30 km southeast of Newcastle. Water depths in the area are around 150 m and the total depth of the well is expected to be about 2,150 m. The reservoir target is Permo-Triassic, similar to that in the Bowen basin of Queensland. Source rocks are the Permian coal beds.
A number of onshore wells have been drilled in the Sydney basin, beginning in the early 1900s, some with gas flows to surface, but none were commercial.
The offshore sector has attracted a number of companies since the early 1980s, including Santos and Ampolex, and several seismic surveys have been run that indicated up to 10 prospects with potential to hold several tcf of gas.
Advent and Bounty drilled New Seaclem-1 60 km east of Newcastle in December 2010, the only offshore well so far. It was dry.
Advent, an unlisted oil and gas company owned by BPH Energy, Grandbridge, and MEC Resources, holds an 85% interest and operatorship of PEP 11. Bounty Oil and Gas NL holds the remaining 15%.
Drilling & Production Quick Takes
Neptune begins Seagull drilling offshore UK
Neptune Energy and joint venture partners started drilling on the Seagull project on license P1622 Block 22/29C, 17 km south of the BP-operated Eastern Trough Area Project central processing facility (ETAP CPF) in UK Central North Sea. The development will be tied back to the ETAP CPF, partially utilizing existing subsea infrastructure (OGJ Online, Sept. 23, 2020). Gas from the development will come onshore at the CATS processing terminal at Teesside, while oil will come onshore through the Forties Pipeline System to the Kinneil Terminal at Grangemouth.
The Gorilla VI (JU-248) jackup rig, operated by Valaris, will drill four wells for the development over the course of the campaign, which is expected to last 18 months. Seagull is expected to produce 50,000 boe/d. Proved plus probable gross reserves are estimated at 50 million boe.
Neptune is operator of Seagull (35%) with joint venture partners BP (50%) and JAPEX (15%).
Johan Sverdrup partners eye third capacity increase
Equinor and its Johan Sverdrup partners have agreed to further production capacity increases from the North Sea field.
The field is now expected to deliver up to 535,000 b/d of oil by mid-2021, dependent on water-injection, which is planned for this year. The increase will be the third since the field came on stream in October 2019 (OGJ Online, Oct. 7, 2019; Nov. 18, 2020). Overall, the increase is some 100,000 bbl more than the original basis.
Plant capacity was tested in November 2020 to verify a possible production rise. Rates up to 535,000 b/d were tested.
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. In 2020 one barrel of oil produced at the field emitted below 0.2 kg CO2 – almost 100 times lower than the global average. 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%).
Tulip Oil plans offshore Netherlands drilling
Tulip Oil Holding BV is evaluating rig availability for drilling two discovered gas fields near the producing Q10-A field offshore the Netherlands. The targeted reservoirs have previously produced gas and have field development plans that follow the same approach as development and appraisal of Q10-A for low-cost production and low carbon footprint.
Tulip has taken a final investment decision (FID) on one completion of an unfinished well and one side-track in Q10-A for production in second-quarter 2021. The company is evaluating an additional temporary appraisal sidetrack to test productivity of the proven Vlieland oil formation in the Q7/Q10a license.
Production in Q10-A was shut in until Oct. 13 for scheduled maintenance of the neighboring P15 platform. Since November, production has benefitted from deployment of the available compression facilities on P15. Q10-A field produced 142 million standard cu m gas during fourth-quarter 2020 compared to 59 million standard cu m in the third quarter.
Tulip Oil Netherlands Offshore BV (TONO) is a 100% subsidiary of Tulip Oil Netherlands BV (TON), which is a 100% subsidiary of Tulip Oil. TON is operator and holds 60% interest in exploration licenses M10/M11, while TONO is operator and holds 60% interest in production licenses Q07/Q10a and exploration licenses Q10b, Q08, and Q11. Energie Beheer Nederland BV holds the remaining 40%.
PROCESSING Quick Takes
Shell inks deal to shed Danish refinery, downstream assets
Royal Dutch Shell PLC’s Shell Petroleum Co. Ltd. has agreed to sell subsidiary AS Dansk Shell to PL ESG Denmark Co. ApS (Postlane Partners).
Alongside Dansk Shell’s 68,000-b/d Fredericia refinery, Postlane Partners also will purchase Dansk Shell’s local trading and supply activities, including its existing inventory of refinery feedstocks and finished products, Shell said.
Subject to regulatory approval, the companies plan to complete the transaction in second-quarter 2021.
In line with Shell’s strategy to meet the cleaner energy needs of its customers, the operator said the Danish divestment will complete the company’s exit from downstream activities in Denmark as well as support the ongoing global downsizing of its 14-site refining portfolio to six integrated energy and chemicals parks to further its goal of becoming a net-zero emissions energy business by 2050 or sooner.
Shell said it will retain a presence in Denmark via its 49% interest with partner DCC Energi AS (51%) in DCC & Shell Aviation Denmark AS, which supplies aviation fuels to seven Danish airports.
The new sales agreement with Postlane Partners follows Shell’s cancellation of a 2016 deal to sell its downstream holdings in Denmark to Dansk Olieselskab APS.
Shell previously sold Dansk Shell’s retail, commercial fuels, and aviation businesses in Denmark to Canadian-based convenience store firm Alimentation Couche-Tard Inc., Laval, Que., in 2016, followed by sale of its Danish upstream assets to Norwegian Energy Co. ASA (Noreco) in 2019.
In addition to retaining Dansk Shell’s existing 260 employees, independent renewable-energy investment firm Postlane Partners plans to equip the Fredericia refinery for coprocessing of bioproducts, as well as carry out work focused on green hydrogen and the potential for advanced biofuels, Shell said.
In a separate release, Shell assured the sale of its refinery will in no way impact supply of Shell-branded fuels to the Danish market, as DCC Energi will continue under its existing licensing agreement to market and sell Shell products in Denmark.
DCC Energi, which operates Denmark’s 234 Shell-branded retail stations, also supplies Shell heating oil, lubricants, natural gas, diesel, and gas-to-liquids (GTL) fuel to Danish customers.
Lukoil commissions new unit at Volgograd refinery
PJSC Lukoil subsidiary OOO Lukoil Volgogradneftepererabotka has commissioned a new deasphalting plant at its 14.8-million tonnes/year Volgograd refinery in southern Russia.
The new plant, which also includes a fractionation unit, entered operation on Jan. 29, Lukoil said in a release.
Part of Lukoil’s ongoing 172-billion rouble investment over the years to modernize the Volgograd refinery, the new 10-billion rouble plant comes as part of the operator’s program to upgrade its lubricants production assets to deliver high-quality finished products complying with international environmental standards to help reduce Russia’s reliance on importing these products from abroad, the company said.
The new plant’s production of high-viscosity base stocks will enable the refinery to produce engine oils with increased oxidation resistance suitable for use in industrial vehicles and cargo trucks operating in rough environments and cold weather.
The Volgograd refinery also is continuing construction of the second stage of its 20-Mw solar power plant (SPP) that—scheduled for startup in 2021—will increase the site’s SPP total capacity up to 30 Mw and provide an additional 24 million kw-hr of green energy annually, which is equivalent to a 12,000-tpy reduction in carbon dioxide emissions, Lukoil said.
As part of the broader program to modernize its Russian refining system, Lukoil said by yearend 2021 it will commission a new isomerization unit as well as a 2.1-million tpy delayed coking complex at Lukoil Nizhegorodnefteorgsintez’s 17-million tpy Kstovo refinery in central Russia’s Nizhny Novgorod region. Between 2011-20, Lukoil said it has invested over 163 billion roubles on the modernizations.
TRANSPORTATION Quick Takes
NextDecade cancels proposed Galveston Bay LNG plant
NextDecade Corp. has completed evaluation of the Galveston Bay LNG site and determined that the site in Texas City, Tex., is not suitable for development of its planned 16.5-million tonne/year (tpy) LNG plant.
The US Army Corps of Engineers (USACE), Galveston District, advised that a portion of the Galveston Bay LNG site is under federal navigation servitude as an active dredged material placement area (DMPA) for the Texas City Ship Channel Federal Project. The Galveston Bay LNG project cannot be constructed without USACE requesting that Congress – via the Water Resources Development Act or other legislation – authorize the release of its constitutional right of navigation servitude over this DMPA.
Due to the potential for prolonged uncertainty around the prospect of such a release by USACE, NextDecade has forfeited the Galveston Bay LNG site and will no longer make lease payments to the site’s landholders, the Texas General Land Office and the City of Texas City. NextDecade has also informed the Federal Energy Regulatory Commission (FERC) of its intent to withdraw Galveston Bay LNG from FERC pre-filing proceedings and cease all related activities. The company also requested that the US Department of Energy terminate its June 2018 authorization for export of LNG from Galveston Bay LNG.
NextDecade said that the decision further enhances the value of and need for its 27-million tpy Rio Grande LNG plant in the Port of Brownsville, Tex., where late-stage development activities are ongoing. NextDecade added that it continues to work on remaining commercial agreements needed to achieve a final investment decision (FID) on Rio Grande LNG in 2021.
The company last year cut the plant’s planned six production trains to five. Rio Grande LNG is expected to be complete in late 2023, pending timely FID.
Power of Siberia extension 12% complete
Gazprom has completed construction of 98 km of a natural gas pipeline that will link Kovyktinskoye field to Chayandinskoye field in Yakutia. The planned 803-km pipeline is an extension of Gazprom’s Power of Siberia system, which currently delivers Chayandinskoye gas to China.
The company describes work to bring its 1.8-trillion cu m Kovyktinskoye field online as proceeding according to schedule, with development drilling continuing, filling works underway for the highest-priority well clusters, and two gas treatment plants under construction. Gazprom plans to start shipping gas from the field through Power of Siberia in late 2022.
Power of Siberia began deliveries in late 2019, entering China under the Amur River near Blagoveshchensk.
Gazprom expanding Far East natural gas pipeline
OAO Gazprom is expanding the Sakhalin–Khabarovsk–Vladivostok gas trunkline between Komsomolsk-on-Amur and Khabarovsk in Russia’s Far East. More than 300 km of 48-in. OD pipe–in excess of 75% of the new leg’s overall length–has been welded.
The new section will supply gas to consumers in Khabarovsk Territory, and establish new connections for consumers receiving gas via the Okha–Komsomolsk-on-Amur gas pipeline, which is slated for potential decommissioning.
In September 2020, Gazprom and the Khabarovsk Territory approved a program for gas supply and gas infrastructure expansion in the region for a new 5-year period, 2021-25. The company’s investments in the program will total RUB 5.49 billion ($72 million)–a 3.2-fold increase against the investments made 2016–20. Gazprom plans to build 14 inter-settlement gas pipelines, 9.3 km of gas pipeline branches, and six gas distribution stations.
Once complete, the project will supply 20 communities in the Amursky, Bikinsky, Khabarovsky, Komsomolsky, and Ulchsky Districts, as well as potential industrial consumers in Nanaisky District.