GENERAL INTEREST Quick Takes
Shell sells Appalachia assets for $541 million
Royal Dutch Shell PLC, through its affiliate SWEPI LP, has agreed to sell its Appalachia shale gas position to National Fuel Gas Co. (NFG) and its subsidiaries, Seneca Resources Co. LLC, National Fuel Gas Midstream Co. LLC, and NFG Midstream Covington LLC, for $541 million.
The sale includes transfer of about 450,000 net leasehold acres across Pennsylvania, with about 350 producing Marcellus and Utica wells. Included in the leasehold are over 200,000 net acres in Tioga County, with net proved developed natural gas reserves of approximately 710 bcf. At closing, these assets are expected to have flowing net production from both the Utica and Marcellus shale formations of 215-230 MMcfd, with shallow base declines and an average net revenue interest of 86.5%. Assets include some 142 miles of gathering pipelines and related compression, over 100 miles of water pipelines, and associated water handling infrastructure, all of which currently support Shell’s Tioga County production operations. These gathering facilities are interconnected with various interstate pipelines, including National Fuel’s Empire pipeline system, with the potential to tie into its existing Covington gathering system.
The consideration is intended to be paid in cash, but National Fuel has the option to provide up to $150 million of NFG common stock as consideration. If not paid fully in cash, there will be two contingent payments of up to $15 million for each of the years 2021 and 2022 depending on certain market conditions, in which the payment will be pro-rata reduced if National Fuel elects for less share compensation at close.
The transaction is expected to close on July 31, with an effective date of Jan. 1, and is subject to customary closing conditions.
Alaskan explorers Energy 88, XCD Energy to merge
Two small Perth-based Alaskan explorers, 88 Energy Ltd. and XCD Energy Ltd., have agreed to merge.
The agreement comes following a recent unsolicited takeover bid by 88 Energy on XCD which offered 1.67 new 88 Energy shares for every XCD Energy share and 0.5 of 88 Energy shares for each XCD option.
88 Energy revised its bid and now directors of both companies have unanimously recommended an off-market takeover offer whereby 88 Energy will issue 2.4 shares for every XCD share held along with 0.7 of 88 Energy’s shares for every XCD listed option.
The offer is subject to a formal bidder’s statement, the absence of a superior offer, an independent expert’s report judging the offer fair and reasonable and at least a 90% acceptance level from XCD shareholders and listed option holders.
If successful, XCD Energy will become a wholly-owned subsidiary of 88 Energy with XCD shareholders owning 20% interest of the new entity.
88 Energy’s managing director, David Wall, already holds 4.2% of XCD shares, while the 88 Energy non-executive chairman, Michael Evans, holds 0.57% of XCD.
Both companies said the merged entity will have a diversified portfolio of exploration projects on the Alaskan North Slope. XCD holds 195,373 acres of land on the North Slope while 88 Energy’s leases total 250,000 acres.
The three main prospects will be the Project Icewine, leases in the Yukon, and Project Peregrine.
Project Icewine, from 88 Energy’s portfolio, includes the recently drilled Charlie-1 exploration well while XCD’s Project Peregrine permits lies 15 km from the recent ConocoPhillips’ Harpoon discovery. Harpoon is also on trend and analogous to XCD’s Harrier prospect.
Qatar Petroleum to farm in to blocks offshore Mexico
Qatar Petroleum has signed three farm-in agreements to acquire about 30% of Total SA’s participating interest in Blocks 15, 33, and 34 in the Campeche basin, offshore Mexico.
The blocks lie within 30-90 km of Cantarell and KMZ oil fields in water depths of 10-1,100 m. The total area covered by the blocks is about 2,300 sq km.
Each farm-in agreement is subject to customary regulatory and other approvals by Total’s existing partners and the government of Mexico.
Exploration & Development Quick Takes
Petrobras makes discoveries in Búzios, Albacora fields
Petrobras discovered oil in the pre-salt of Búzios field, Santos basin and Albacora field, Campos basin, off Brazil.
Búzios exploration well 9-BUZ-39DA-RJS is in the southeast area of the field, 210 km from Rio de Janeiro, in 2,108 m water depth. The well is in the drilling process and has already identified 208 m of reservoir with oil of similar quality to current field production. The tests were carried out at 5,400 m depth.
Albacora exploration well 9-AB-135D-RJS is inside Plano de Avaliação de Descoberta (PAD) of the Forno area, 184 km from Macaé, Rio de Janeiro, in 450 m water depth. The discovery consists of about 214 m of reservoir with presence of light oil proven through tests carried out at 4,630 m depth.
Petrobras is the operator (90%) of the Búzios field consortium in partnership with CNOOC (5%) and CNODC (5%) (OGJ Online, Nov. 7, 2019). Petrobras is the operator and sole owner of Albacora field.
Galilee completes second well on Kumarilla CSG project
Galilee Energy Ltd., Brisbane, has successfully completed the second well in its 100%-owned Kumbarilla coal seam gas project in permit ATP 2043 in the Surat basin of southeast Queensland.
The well intersected 25 m of net coal with strong gas shows in the Walloon subgroup Juandah and Taroom coal measures.
The result indicates there is good net coal thickness in the Walloon subgroup across the Kumbarilla project area.
The rig has moved to the third location for the final well in the first phase of exploration.
The third well will evaluate the coal properties and fracture-enhanced permeability potential of the Walloon on the southern side of the Moonie-Goondawindi Fault System that bifurcates the permit.
The first two wells evaluated the northern and central areas respectively, however the southern side is untested and has been assessed as geologically independent to the two previous drilling locations in terms of potential fracture development.
Galilee said the Kumbarilla project has been independently certified to host a potential 2C contingent resource of 504 petajoules of gas.
Woodside lets contract Lambert Deep, Greater Western Flank fields
Woodside Energy Ltd. has let an integrated engineering, procurement, construction, and installation contract to TechnipFMC for work on the North West Shelf offshore Western Australia.
The contract, worth up to $250 million (Aus.) is for development of Lambert Deep and Phase 3 of the Greater Western Flank fields 126 km northwest of Dampier in the Pilbara region.
The work involves design, manufacture, delivery, and installation of subsea equipment, including a subsea production system, flexible flowlines and umbilicals for connection to the existing Angel platform which is connected by a 50 km subsea pipeline to the North Rankin complex which in turn is part of the Woodside-operated North West Shelf Project infrastructure.
The new contract is the second under the recently awarded 5-year iEPCI frame agreement between Woodside and TechnipFMC.
Woodside intends to drill four new production wells to support the project, three into the Goodwyn GH reservoir on Greater Western Flank fields and one into Lambert Deep field. Drilling is expected to begin in 2021.
Activity will take place across production licenses WA-5-L, WA-16-L, and WA-3-L, the latter containing the Angel platform.
Water depths in the region vary between 80-130 m.
There will be some modification of the Angel platform topsides to accommodate the increased production.
Drilling & Production Quick Takes
Equinor lets rig contract for Martin Linge
Equinor AS has let a contract to Maersk for the hybrid jack-up rig Maersk Intrepid to drill three wells and plug one on Martin Linge oil and gas field in the North Sea.
The contract, valued at $100 million, is scheduled to take effect in September and includes an option to drill one well. The contract value includes rig modifications and upgrades and exclusive of intervention activities, integrated services and any incentive payments for safe and efficient operations. The integrated services in the rig contract are managed pressure drilling (MPD), slop treatment, cuttings handling and tubular running services.
“This will be the first jack-up rig to have a hybrid package retrofit as one of several initiatives to reduce greenhouse gas emissions during operations. The rig will also be prepared for the use of automated drilling technology. So far, the rig has been used to improve the bed capacity on the Martin Linge platform,” said Erik Gustav Kirkemo, senior vice president for drilling and well, Equinor.
Martin Linge field lies 42 km west of Oseberg in water depth of 115 m. The main reservoir is structurally complex and contains gas and condensate at high pressure and high temperature. There are three reservoirs in Middle Jurassic sandstones in the Brent Group at a depth of 3,700-4,400 m. Oil has also been found in the Frigg formation of Eocene age. The main reservoir lies at a depth of 1,750 m and the reservoir quality is good. The field is scheduled to come on stream at the end of this year.
Equinor operates Martin Linge with 70% (OGJ Online, Nov. 27, 2017). Petoro holds the remaining interest.
PetroTal shuts in Bretana oil field
PetroTal Corp. shut in Bretana oil field in Block 95 due to storage capacity limitations resulting from shut down of the Northern Oil Pipeline (ONP) from a Peruvian government public health directive.
The pipeline, operated by Petroperu, has temporarily shut down to combat spread of COVID-19 in communities adjacent to pipeline operations. The directive states that no employees over age of 60 nor with serious chronic diseases should be working in high-risk regions of Peru.
The shutdown is being managed to ensure that operations can return to full production upon reopening of the ONP. PetroTal will move to significantly curtail all costs related to oil field operations, as the company moves into a temporary hibernation mode.
Bretana lies in Maranon basin along the Ucayali River in Peru and is owned and operated by PetroTal. In April, the company brought online its third horizontal well in the field (OGJ Online, Apr. 21, 2020). The field reached record quarterly production of about 9,688 b/d and sales of 9,937 b/d during the year’s first quarter.
Serica contracts rig for Rhum-3 intervention
Serica Energy PLC contracted Awilco Drilling’s WilPhoenix for intervention of Rhum-3 (R3) in Block 3/29a, Northern North Sea.
The work will recover debris left in the well by the previous operator and remove an obstruction believed to be across parts of the downhole completion. The well will be recompleted and put into production. R3 is already connected to the subsea production infrastructure.
Rhum is a gas condensate field producing from two subsea wells, R1 and R2, tied into the Bruce facilities through a 45 km pipeline. Rhum production is separated into gas and condensate and exported to St. Fergus and Grangemouth, respectively, along with Bruce and Keith production (OGJ Online, Nov. 30, 2018). The wells are capable of producing at combined rates approaching 30,000 boe/d (gross), of which over 95% is gas. The field has produced at relatively constant rates with limited reservoir decline evident through the past year. Average production in 2019 was 13,775 boe/d net to Serica.
WilPhoenix is a 3rd-generation, enhanced pacesetter, harsh-environment, mid-water, semi-submersible drilling rig. Operations are expected to begin in this year’s fourth quarter and last 70 days.
Serica is partner and operator at Rhum (50%) with Iranian Oil Co. (UK) Ltd. (50%).
PROCESSING Quick Takes
IOC lifts crude throughputs, production across Indian refining system
Indian Oil Corp. Ltd. has restarted several processing units at its refineries as demand for finished petroleum products gradually continues to increase in the wake of India’s countrywide lockdown instituted in March to curb the outbreak of coronavirus (COVID-19).
With crude oil throughputs across the refining system steadily rising, IOC’s refineries were operating at about 60% of their design capacities as of May 11, the operator said in a release.
While IOC disclosed no details regarding the specific units that have been restarted, the refineries at which the units are located, or current processing rates of individual refineries, the operator did confirm it plans to scale up operations across its refining system to 80% of design capacity by the end of May.
Announcement of IOC’s plan for its post-lockdown scenario follows the company’s late-March confirmation that it reduced crude throughputs at most of its refineries by 25-30% as the COVID-19 crisis eroded product demand across the country (OGJ Online, Mar. 26, 2020).
While it has kept all of its refining units on hot standby in preparation to ramp up throughputs once product demand picks up, IOC confirmed the steep drop in domestic demand ultimately resulted in forcing the operator to reduce overall throughputs and operations at its refineries to 45% of their design capacities by the first week of April.
With an overall group refining capacity of more than 80.7 million tonnes/year—the largest share among domestic refining companies—IOC controls 11 of India’s 23 refineries directly and via subsidiaries to account for a 32.36% share of total national refining capacity.
Alongside ramping up crude throughputs, IOC said as of May 11, it also had restarted the monoethylene glycol (MEG) plant and naphtha cracker—resuming production of high-density polyethylene (HDPE) and polypropylene—at its Panipat refinery and petrochemical complex in Haryana, north of New Delhi. Restart of the naphtha cracker additionally will help the Panipat refinery further boost crude throughputs, according to the operator.
IOC said it also plans to restart the polypropylene plant at its Paradip refining complex in Odisha, on India’s northeastern coast—as well as other unnamed polymer units at unidentified sites—by the end of May.
Turnaround under way at Unipetrol’s Litvínov refinery, petrochemical complex
Unipetrol AS, a subsidiary of Polski Koncern Naftowy SA (PKN Orlen), is progressing with a modified version of its regularly scheduled 4-year major turnaround at its Chempark Záluží petrochemical complex in Litvínov, Czech Republic, which includes refining arm Unipetrol RPA SRO-Rafinerie’s 5.4 million-tonnes/year Litvínov refinery.
The turnaround—for which controlled shutdown of production units began on Apr. 9 for start of maintenance activities on Apr. 15—is now in full swing, though at a modified scope as part of measures to ensure safety and health of workers at the site during the ongoing coronavirus (COVID-19) crisis, Unipetrol said in a post to its official LinkedIn account as well as updates on the company’s website.
While the turnaround’s original scope was to include 5,800 maintenance activities, the operator halved that number to a necessary minimum of about 2,300 activities focusing only on projects aimed at ensuring upgrades, maintenance, and preparation of production technologies for the next 4-year production cycle.
Unipetrol said key projects during the scheduled maintenance period include repair of the refinery’s atmospheric distillation unit’s furnace, replacement of underground pipes for cooling water in the partial oxidation production unit, and service repairs of large compressors in the complex’s steam cracker.
Alongside revising the scope of projects to be executed during the planned shutdown, Unipetrol also reduced turnaround personnel to 1,260 individuals from an originally planned staff of 2,800.
All turnaround work is scheduled to be completed on May 31, with production units to be gradually put back into operation through June 14, Unipetrol said.
FID stalled for proposed Ohio ethylene complex
PTTGC America LLC (PTTGCA), the US subsidiary of Thailand’s PTT Global Chemical (PTTGC), and partner Daelim Chemical USA LLC, a subsidiary of South Korea’s Daelim Industrial Co. Ltd., are delayed as a result of the coronavirus (COVID-19) pandemic in reaching final investment decision (FID) on the partnership’s (PTTDLM) proposed 1.5 million-tonnes/year ethane cracker and petrochemical complex planned for Mead Township along the Ohio River in Shadyside, Belmont County, Ohio (OGJ Online, Oct. 28, 2015; Apr. 22, 2015).
While PTTDLM cited unidentified factors resulting from the COVID-19 health crisis as the cause of the delay, the partnership confirmed that, despite the pandemic, project leaders are continuing to work with key partners toward the project’s FID.
With the first phase of site preparation, engineering, and design work for the project completed as of late February, PTTDLM also said it now plans to continue investing in safety of the project site’s surrounding neighborhood by demolishing vacant structures.
Confirmation of delayed FID on the project follows PTTDLM’s Feb. 28 announcement that it was working toward finalizing project financing and supply agreements ahead of an anticipated FID by midyear.
According to a final air pollution permit-to-install (PTI) issued on Dec. 21, 2018, by the Ohio Environmental Protection Agency, PTTDLM’s proposed complex—which will be equipped with six ethane-cracking furnaces—will produce ethylene, high-density polyethylene (HDPE), and linear low-density polyethylene (LLDPE) using the following units and capacities:
- Ethylene plant, 1. 5 million tpy.
- HDPE Unit 1, 350,000 tpy.
- HDPE Unit 2, 350,000 tpy.
- LLDPE-HDPE Unit 1, 450,000 tpy.
- LLDPE-HDPE Unit 2, 450,000 tpy.
The proposed multibillion-dollar complex will also include on-site railcar and truck loading, supporting utilities, infrastructure, storage tanks, logistics facilities, and installations for either production or provision of required natural gas, water, air, nitrogen, steam, and electricity to support operation of process units, according to the PTI.
TRANSPORTATION Quick Takes
Sempra delays Port Arthur LNG FID to 2021
Sempra Energy has delayed final investment decision on its 13.5-million tonne/year (tpy) Port Arthur LNG liquefaction plant from third-quarter 2020 to 2021 due to current market dynamics. Earlier in 2020, Port Arthur LNG LLC and Bechtel Oil, Gas, and Chemicals Inc. signed a fixed-price EPC contract for Sempra’s Port Arthur LNG liquefaction project under development in Jefferson County, Tex. (OGJ Online, Mar. 3, 2020).
Infraestructura Energética Nova SAB de CV (IEnova), Sempra’s subsidiary in Mexico, meanwhile is actively monitoring market dynamics but, as a result of the current pandemic, Sempra said it is reasonable to expect some of its construction capital to be deferred to 2021 from 2020. IEnova and Sempra LNG are seeking to add liquefaction to the existing Energia Costa Azul regasification terminal in Ensenada, Baja California, Mexico. The project is being developed in two phases with an initial 2.4-million tonne/year Phase 1.
Sempra recently announced that Cameron LNG has reached final commissioning of the 14.95-million tpy Phase 1 of its liquefaction-export project in Hackberry, La., as the third of three liquefaction trains achieved mechanical completion, introduced feed gas, and initiated start-up. The project remains on track to produce LNG from the third and final Phase 1 train in second-quarter 2020 and begin commercial operations in third-quarter 2020.
Cameron LNG began commercial operations of Train 1 and Train 2 in August 2019 and February 2020, respectively.
Sempra indirectly owns 50.2% of Cameron LNG. Cameron LNG is jointly owned by affiliates of Sempra LNG, Total SA., Mitsui & Co. Ltd., and Japan LNG Investment LLC, a company jointly owned by Mitsubishi Corp. and Nippon Yusen Kabushiki Kaisha.
Sempra Energy earned $760 million in first-quarter 2020, compared with first-quarter 2019 earnings of $441 million.
Anchor developers award offshore gas transport to Williams
Chevron and Total E&P USA Inc. have contracted Williams to provide offshore natural gas transportation services to their joint Anchor development, 140 miles off the coast of Louisiana in the Green Canyon area of the Gulf of Mexico.
Chevron plans to drill multiple wells and construct a floating production platform capable of handling rich natural gas and oil production from the Anchor development. Williams will leverage existing infrastructure to transport Anchor’s natural gas production to the Discovery system, of which Williams is 60% owner and operator and DCP Midstream is 40% owner. The rich natural gas will be transported to Discovery’s 600-MMcfd processing plant in Larose, La., and the NGL will be fractionated and marketed at Discovery’s 35,000-b/d Paradis plant in Louisiana.
Anchor’s partners expect it to come online first-half 2024. In water depths of 5,000 ft (1,524 m), Stage 1 development of the project will consist of a seven-well subsea development and semi-submersible floating production unit (FPU).
The planned FPU has a design capacity of 75,000 b/d of crude oil and 28 MMcfd of natural gas. Total potentially recoverable resources for Anchor are estimated to exceed 440 million boe.
Chevron, through its subsidiary Chevron USA Inc., is operator and holds a 62.86% working interest in the Anchor project. Co-owner Total E&P USA Inc. holds 37.14% working interest.