GENERAL INTEREST Quick Takes
Hess increases ownership in Kaieteur block, offshore Guyana
Hess Corp. increased its working interest in Kaieteur block, offshore Guyana, to 20% from 15%. The increase occurred on the back of the Tanager-1 oil discovery, and via the farm-down of a 5% working interest by Cataleya Energy Ltd. to Hess (OGJ Nov. 17, 2020).
Tanager-1, the first well drilled on the block, encountered 16 m net oil pay (20° API oil) in high-quality sandstone reservoirs of Maastrichtian age and confirmed the extension of the Cretaceous petroleum system and Liza play fairway outboard from discoveries on the nearby ExxonMobil-operated Stabroek block. The discovery is currently considered to be non-commercial as a standalone development.
High quality reservoirs were also encountered in Tanager-1 at the deeper Santonian and Turonian intervals though interpretation of the reservoir fluids was reported to be equivocal and require further analysis.
Post-well analysis indicates the Tanager-1 Maastrichtian discovery contains best estimate unrisked gross 2C contingent oil resource of 65.3 million bbl (17.7-131 million bbl low to high range) with a best estimate unrisked net 2C contingent oil resource attributable to the Kaieteur block of 42.7 million bbl (11.3-86 million bbl low to high range).
In addition to the Tanager-1 oil discovery, a substantial Cretaceous prospect inventory has been mapped across the 5,750-sq km 3D seismic survey in the southern part of the block, where the Kaieteur JV partners are currently high grading the next potential drilling targets.
After farm down, Esso Exploration and Production Guyana Ltd. remains operator of the Kaieteur JV (35%) with partners Ratio Guyana Ltd. (25%), Cataleya Energy Ltd. (20%), and Hess Guyana (Block B) Exploration Ltd. (20%).
Malampaya Energy to acquire Shell Stake in Malampaya gas field
Malampaya Energy XP Pte Ltd., a subsidiary of Udenna Corp., signed an agreement with Shell Petroleum NV to acquire Shell Philippines Exploration BV (SPEX), which holds a 45% share and operatorship of Service Contract 38 (SC38) including Malampaya gas field off Northwest Palawan Island.
Consideration for the sale is $380 million, with additional payments of up to $80 million from 2022-2024 contingent on asset performance and commodity prices, Shell said in a May 20 release.
The major components of Malampaya include subsea wells and flowlines, a shallow water platform and a depletion completion platform to process natural gas, a catenary anchored leg mooring-buoy for the export of liquid condensate, a 504-km long gas export pipeline on the seabed, an onshore gas plant and pipeline in Batangas City.
The project will be 100% operated by Filipinos following the deal, with Malampaya Energy (45%), Philippine National Oil Co. Exploration Corp. (10%), and UC38 LLC (45%) as joint venture partners, Malampaya said in a separate release.
Malampaya delivers a fifth of the Philippines’ growing electricity requirements through the supply of natural gas to five power plants in Luzon. The asset has been in operation since 2002.
Belinda Racela, a Malampaya Energy executive, said the company is accelerating exploration and production plans to extend the life of Malampaya field.
SPEX staff will continue their employment under the new ownership, Shell said.
Subject to partner and regulatory consent, the transaction is targeted to complete by end-2021.
EnVen to add Neptune interest, operatorship with BHP deal
EnVen Energy Ventures LLC has agreed to acquire BHP’s 35% ownership interest and operatorship of Neptune field in the deepwater Gulf of Mexico.
Neptune field consists of Atwater Blocks 573, 574, 575, 617, and 618, about 120 miles off Louisiana. Water depths are 4,200-6,500 ft.
Development includes six subsea wells tied back to a tension-leg platform (TLP) installed on Green Canyon block 613 in 4,250 ft of water above the Sigsbee escarpment (OGJ Online, June 18, 2007). The single-column TLP can process as much as 50,000 bo/d and 50 MMcfd of natural gas.
Production began in July 2008 (OGJ Online, July 7, 2008). Crude oil is transported via the Caesar pipeline, while natural gas is exported via the Cleopatra pipeline.
The Neptune joint venture is operated by BHP (35%) with co-owners EnVen Energy Ventures LLC (30%), W&T Energy VI LLC (20%), and 31 Offshore LLC (15%).
BHP, who has served as Neptune operator for the last 10 years, will continue as such under contract as part of the transition agreement until transfer of both operatorship and ownership are approved by the regulator.
Exploration & Development Quick Takes
State Gas finds success in Rougemont-1 CSG well
State Gas Ltd., Brisbane, found early success in its Rougemont-1 exploratory coal seam gas well in the 100%-owned ATP 2062 permit in the Bowen basin of central Queensland.
The well reached total target depth of 800 m, intersecting 8 m of net coal in Bandanna coal measures.
Well logs confirm the coal was encountered in a number of seams. The top seam encountered at 495 m depth and the thickest measuring 2.2 m—consistent with nearby Bandanna CSG projects at Arcadia Valley (Santos-GLNG) and Mahalo (Santos-APLNG-Comet Ridge).
Gas was seen bubbling from core samples taken from the coal seams. Further testing is under way.
Richard Cottee, executive chairman, said the early result justifies the company’s decision to compete for new acreage in the region and strengthens the view that Bandanna coals will be developed synergistically with the company’s 100%-owned Reid’s Dome gas discoveries in production licence PL-231 to the southwest.
Conventional gas was found at Reid’s Dome in 1955, but it wasn’t until 2018 that State Gas drilled the first CSG well (Nyanda-4) into the structure and found gas in the Reid’s Dome coal measures. The discovery was confirmed in 2019 with Aldinga East-1A and Serocold-1.
Rougemont-1 is the first of a two-well program in ATP 2062 to evaluate the Bandanna coals in the eastern arm of the permit awarded to State Gas late in 2020.
Both the Rougemont and Reid’s Dome wells are close to existing gas pipelines and can be quickly linked to eastern Australian markets.
PTTEP find gas offshore Malaysia
PTT Exploration and Production Public Co. Ltd. (PTTEP) subsidiary PTTEP HK Offshore Ltd. (PTTEP HKO) discovered gas at Kulintang-1, the first exploration well in Block SK438 in shallow waters, about 108 km off the coast of Sarawak (Bintulu), Malaysia. The company plans to drill another exploration well in the block in this year’s second quarter, it said in a May 19 statement.
Kulintang-1 was drilled to 2,238 m total depth in April. The well encountered gas in the Oligocene to Middle Miocene sandstone reservoirs, which has not been fully evaluated before, said partner Petronas in a separate statement.
The gas discovery “proves further potential of sweet gas in the [Balingian] province, especially in the deeper Oligocene play,” said Petronas Senior Vice-Pres. of Malaysia Petroleum Management, Mohamed Firouz Asnan.
In March, PTTEP discovered oil and gas in the Sirung-1 wildcat exploration well in Block SK405B, also in the Balingian Province (OGJ Online, Mar. 30, 2021).
PTEEP HKO is operator of Block SK438 with 80% participating interest. Petronas Carigali Sdn. Bhd. holds 20%.
PGNiG expands Pakistan presence with license farm in
Polskie Górnictwo Naftowe i Gazownictwo (PGNiG) plans to evaluate the resource potential of the Musakhel license through seismic surveys scheduled to begin in 2022 having recently acquired a 25% interest in the central Pakistan asset. Based on data from deposits discovered in the vicinity, the company estimates license resources of 16 billion cu m (bcm) of natural gas.
The 2,176-sq km block lies in the northeastern part of Pakistan’s Balochistan province. Analysis of the seismic data will be a starting point to design drilling operations, the company said in a May 19 release, and energy infrastructure investment projects executed in recent years in adjacent areas will facilitate development of potential resources, the company continued.
Pakistan Petroleum Ltd. is operator with 37.2% interest. Partners are Oil & Gas Development Co. Ltd. (35.3%), PGNiG (25%), and Government Holdings Pvt. Ltd. (2.5%).
Currently, PGNiG has exploration and production operations in Pakistan in the Kirthar license area, Sindh province, where two fields, Rehman and Rizq, are producing for the company. Since 2015, PGNiG has operated a gas production facility on Rehman field—its first gas production facility outside Poland.
In 2020, PGNiG’s gas production in Pakistan was about 300 million cu m, an increase of 50% year-on-year. The company plans to continue exploration work on the Kirthar license area and plans to drill and develop further production wells on Rehman and Rizq fields.
Drilling & Production Quick Takes
Norway production decreased in April, NPD says
Norway’s liquids production averaged 2.008 million b/d in April, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 2.094 million b/d in March (OGJ Online, Apr. 20, 2021).
Oil production in April is 3.2% higher than the NPD’s forecast, and 0.7% higher than the forecast so far this year.
The average daily liquids production in April consists of 1.725 million b/o, 270,000 bbl of NGL, and 13,000 bbl of condensate.
The total petroleum production for the first 4 months in 2021 is about 78.0 million standard cu m oil equivalents.
Buru set for 2021 Canning basin drilling program
Buru Energy Ltd., Perth, and joint venture partner Origin Energy Ltd., Sydney, have begun moving a rig onto location for the first well of a back-to-back, three-well 2021 exploration and appraisal drilling program in the onshore Canning basin in northern Western Australia.
Buru expects to spud wildcat Currajong-1 (formerly Kurrajong-1, but renamed to differentiate it from an offshore well) mid-June.
Currajong lies in the western section of exploration permit EP391 about 30 km west of the company’s Ungani oil field. The wildcat has similar geology to Ungani and the prospect has potential to hold around 30 million bbl, the operator said.
Currajong-1 will be directly followed by Rafael-1, a wildcat in the eastern section of EP391 about 50 km east of Ungani. A spud date is expected late July or early August.
The new prospects are two of the largest conventional oil targets to be drilled in Australia for several years, the company said.
Origin will carry Buru through exploration drilling for up to $16 million (Aus.) in a farm-in deal for 50% interest in the permit.
The third well in the program is Ungani-8, a horizontal appraisal on Ungani field in production licences L20/L21. It is being drilled into a potential undrained fault block in the structure originally targeted by Ungani 6-H.
The aim is to increase field production rates above the current 800 b/d of oil and add to field reserves.
Ungani is operated by Buru with 50% interest. Roc Oil Ltd., which is owned by Chinese company Fosun International Ltd., holds the remaining 50%.
Shell preps for UK North Sea Pensacola drilling
Shell UK Ltd. let a contract to Fugro GB North Marine Ltd. to carry out geophysical and geotechnical site survey works over the Pensacola gas prospect, UK North Sea license P2252. The work is in preparation for drilling of the Pensacola exploration well, according to a May 24 release from partner Deltic Energy PLC. Shell expects to start drilling in Pensacola in May 2022.
Pensacola is a Zechstein reef upper Permian patch structure covering an area of 15 km by 6 km. It is over 200-m thick and has P50 prospective resources of 309 bcf.
Shell is operator of the license with 70% interest. Deltic Energy holds the remaining 30%.
PROCESSING Quick Takes
IOC lets contract for Paradip refinery’s PTA plant
Indian Oil Corp. Ltd. (IOC) has let a contract to Technip Energies to deliver a suite of services for a portion of the previously announced integrated paraxylene-purified terephthalic acid (PX-PTA) complex to be built at the operator’s 15-million tonnes/year Paradip refinery in Odisha, on India’s northeastern coast.
Technip Energies will deliver engineering, procurement, construction, and commissioning (EPCC) for Paradip’s proposed 1.2-million PTA plant and associated installations, the service provider said on May 10.
Technip Energies valued the EPCC contract at between €250-500 million.
This latest contract follows IOC’s recent award to Maire Tecnimont SPA subsidiaries Tecnimont SPA and Tecnimont Private Ltd. of Mumbai to provide EPCC on the PX-PTA complex’s PX plant and related offsite installations.
Production from the 800,000-tpy PX plant—which will receive its feedstock of reformate from the refinery’s existing UOP LLC-licensed continuous catalyst regeneration (CCR) platforming unit—will be used as feedstock for the complex’s adjacent 1.2-million tpy PTA plant.
In its latest annual report to investors published in August 2020, IOC said the Paradip refinery’s 138.05-billion rupee PX-PTA project—which, at the time, was already under implementation and previously scheduled for commissioning by October 2022—comes as part of the company’s enhanced focus of further integration of its downstream refining and petrochemical operations to meet India’s rising demand for plastics and textiles.
Currently slated for startup in late 2023 or early 2024, the new PX-PTA complex specifically complements IOC’s other petrochemical-related projects at Paradip intended to support the government of Odisha’s plan to establish the Paradip Petroleum, Chemicals, & Petrochemical Investment Region (PCPIR).
In official project documents filed by IOC with the government of India, the operator said the PX plant will consist of an integrated, UOP-licensed aromatics block that includes the following proprietary units and technologies: a xylene fractionation unit; a Sulfolane unit; a benzene-toluene fractionation unit; a Tatoray unit; a Parex unit; and an Isomar unit.
The complex’s PTA will consist of two sections, the first of which will use a feedstock of PX to produce crude terephthalic acid (CTA). A second section of the plant will then use the CTA to produce high-purity PTA, according to IOC.
While IOC has yet to officially confirm specific process technologies to be implemented at the PTA plant, the operator previously said it had selected proprietary technology originally developed and licensed by BP PLC but now owned and licensed by Ineos AG’s Ineos Aromatics business as of Jan. 1, 2021.
Nigeria’s BUA Group lets contract for integrated refining complex
Privately held BUA Group, Lagos, has let a contract to KBR Inc. to provide front-end engineering design (FEED) for a new petrochemical unit to be built at subsidiary BUA Refinery’s 200,000-b/d grassroots integrated refining and petrochemical complex under development in Nigeria’s state of Akwa Ibom.
As part of the contract, KBR will focus on sustainability measures for the new complex, which will include installations for sulfur removal water treatment to meet stringent environmental standards, as well as heat-integration capabilities to ensure long-term production efficiency, the service provider said on May 10.
FEED will examine and recommend sustainable technologies for the complex aimed at reducing greenhouse gas emissions to help limit the site’s carbon footprint, according to KBR.
The FEED award for BUA’s Akwa Ibom complex follows KBR’s earlier completion of the project’s conceptual feasibility study in 2018, KBR said.
Sited in Akwa Ibom to take advantage of the location’s proximity to raw feedstocks and export routes to regional countries, BUA Refinery’s integrated complex—slated for commissioning in 2024—will help reduce Nigeria’s dependence on imported fuels and petrochemicals, as well as reduce the country’s costs of shipping its domestic crude production abroad for refining by other operators, according to BUA.
Chinese operator lets contract for proposed grassroots refining complex
North Huajin Refining and Petrochemical Co. Ltd. (North Huajin) has let contracts to Refining Technology Solutions LLC (RTS)—a subsidiary of E.I. DuPont de Nemours & Co.’s DuPont Clean Technologies division—to provide a suite of services for a hydrotreating unit to be installed as part of the operator’s proposed grassroots integrated refining and petrochemical complex in Liaodong Bay New Area, Panjin, Liaoning Province, China.
Under the agreements, RTS will deliver licensing, basic engineering, and technical services for a 37,000-b/d combined kerosine-diesel hydrotreater (KDHT) that will be equipped with its proprietary IsoTherming hydroprocessing technology for production of fuels complying with Jet 3 fuel and China VI diesel standards, DuPont Clean Technologies said.
Scheduled for startup by yearend 2023, the IsoTherming KDHT unit will enable North Huajin’s refinery reduce its energy requirements and minimize carbon dioxide emissions from the site in line with China’s goal to become carbon neutral by 2060, the service provider said.
The new KDHT comes under North Huajin’s fine chemicals and raw materials project at the planned greenfield complex, which forms a key part of the broader revitalization of northeast China’s rustbelt region, according to DuPont Clean Technologies.
TRANSPORTATION Quick Takes
Woodfibre LNG signs second sales agreement with BP
Pacific Oil & Gas Ltd.’s wholly-owned subsidiary, Woodfibre LNG, has signed a second LNG sales agreement with BP Gas Marketing Ltd., a wholly-owned indirect subsidiary of BP PLC, for delivery from Woodfibre LNG’s planned 2.1-million tonne/year (tpy) plant near Squamish, BC. BP will receive 0.75 million tpy over 15 years on a free-on-board (FOB) basis. The deal increases BP’s total LNG offtake from Woodfibre to 1.5 million tpy.
Woodfibre LNG last year received a 5-year extension from the British Columbia Environmental Assessment Office to begin construction of the plant. The new deadline is Oct. 26, 2025 (OGJ Online, Nov. 2, 2020). The company had hoped to begin construction in third-quarter 2020 and at the time of requesting the extension said it instead expected to begin third-quarter 2021.
NGTL awards 2021 expansion construction contract
Nova Gas Transmission Ltd. (NGTL), a wholly owned subsidiary of TC Energy Corp., awarded Macro Enterprises Inc. subsidiary Macro Construction Inc. a contract to build the Deep Valley South and Colt sections of the 2021 NGTL System Expansion project.
Deep Valley South includes 26 km of 48-in. OD pipeline and Colt includes 14 km of 48-in. pipeline and associated tie-ins.
Planning is under way with pre-construction scheduled to start third-quarter 2021 with completion scheduled end first-quarter 2022. The estimated value of the contract is more than $190 million.
The Canadian government earlier this month approved NGTL’s 2023 North Corridor System Expansion project (OGJ Online, May 4, 2021).
NGTL gets government approval for Alberta gas system expansion
TC Energy Corp. subsidiary Nova Gas Transmission Ltd. (NGTL) has received approval from the Canadian government for its 2023 North Corridor System Expansion natural gas project. The expansion project will add 81 km of pipeline to the existing NGTL system across three sections in northwestern Alberta, expanding capacity from the Peace River area to markets in northeastern Alberta.
The three sections include:
- The North Central Corridor (NCC) Loop (North Star Section 2); 48-in. OD, 24 km about 20 km north of Manning, Alta., in Northern Lights County.
- The NCC Loop (Red Earth Section 3); 48-in., 32 km, about 45 km north of Red Earth Creek, Alta., in Northern Lights County and the municipal district of Opportunity.
- The Northwest Mainline (NWML) Loop No. 2 (Bear Canyon North Extension Section); 36-in., 25 km, about 50 km southwest of Worsley, Alta., in Clear Hills County.
The 2023 North Corridor expansion follows last year’s approval of NGTL’s 2021 System Expansion project.
Approval of the 2023 expansion was contingent on 37 conditions related to safety, environmental, and wildlife protection, Indigenous engagement, and protection of Indigenous rights and interests. It will cost $632 million.